Eagle Rock Energy Partners L P CORRESP Correspondence with SEC

Via EDGAR

January 10, 2014

Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-3561

Re: Eagle Rock Energy Partners, L.P.

Form 10-K for Fiscal Year Ended
December 31, 2012
Filed March 1, 2013
File No. 001-33016

Ladies and Gentlemen:

Set forth below are the responses of Eagle Rock Energy Partners, L.P. (the “Partnership”) to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated December 20, 2013, with respect to the Partnership’s Annual Report on Form 10-K for Fiscal Year Ended December 31, 2012, File No. 001-33016, filed with the Commission on March 1, 2013 (the “2012 10-K”).

For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. The references to page numbers in the response to the Staff’s comments correspond to the pages in the 2012 10-K.

Form 10-K for Fiscal Year Ended December 31, 2012

Business, page 2

Upstream Business, page 19

Developed and Undeveloped Acreage, page 21

1. Please advise or expand your disclosure to present the expiration dates relating to material amounts of your undeveloped acreage to comply with Item 1208(b) of Regulation S-K.

RESPONSE:

We acknowledge the Staff’s comment and respectfully submit our belief that the Partnership’s historical amounts of undeveloped acreage expirations have been immaterial. As of December 31, 2012, the Partnership held interests in approximately 207,471 net acres. Of this acreage, approximately 196,976 net acres (or approximately 95% of the Partnership’s total net acreage position) were held by production. In addition, the Partnership’s acreage subject to expiration (unless production is established or the leases are otherwise renewed or extended) total only 3,046, 1,293 and 1,682 net acres for the years ending December 31, 2014, 2015 and 2016, respectively. Accordingly, we believe that the Partnership’s disclosure on page 21 is consistent with the requirements of Item 1208(b) of Regulation S-K.

Drilling and Recompletion Activity, page 21

2. Please expand your disclosure to provide the number of net wells drilled and clarify if those wells were drilled as exploratory or development wells and were found to be either productive or dry. For additional guidance, please refer to Item 1205 of Regulation S-K.

RESPONSE:

We acknowledge the Staff’s comment and propose to include a table in the 2013 10-K that identifies the gross and net number of exploratory and development wells drilled during each period, as well as whether such drilling efforts resulted in productive wells or dry holes. We note that all wells were productive in 2012, 2011 and 2010.

Oil and Natural Gas Reserves, page 22

Proved Undeveloped Reserves, page 24

3. Please expand your disclosure to present all of the material changes in the proved undeveloped reserves including but not limited to the net quantity of proved undeveloped reserves converted to proved developed reserves and the total dollar amounts of capital expenditures made during the year to convert proved undeveloped reserves to proved developed reserves to comply with Items 1203(b) and 1203(c) of Regulation S-K.

RESPONSE:

We acknowledge the Staff’s comment and respectfully submit that our rationale for more limited disclosure was based on our belief that the change in the Partnership’s total proved undeveloped reserves during 2012 was not material. The Partnership’s proved undeveloped reserves decreased by approximately 4.1 Bcfe, or approximately 4.6%, from approximately 88.5 Bcfe as of December 31, 2011 to approximately 84.4 Bcfe as of December 31, 2012. However, we note your request for expanded disclosure and propose to include additional disclosure in the 2013 10-K regarding changes in the Partnership’s proved undeveloped reserves from period to period. If this disclosure had been included in the 2012 10-K, it would have read as follows:

As of December 31, 2012, our proved undeveloped reserves totaled 57.9 Bcf of natural gas, 2.0 MMBbls of oil and 2.4 MMBbls of natural gas liquids. The total proved undeveloped reserves of 84.4 Bcfe results from a decrease of approximately 4.1 Bcfe, or 4.6%, from total proved undeveloped reserves of approximately 88.5 Bcfe as of December 31, 2011. The changes in our proved undeveloped reserves during 2012 were primarily attributable to:

· An increase of 40.8 Bcfe due to extensions and discoveries, primarily in our Golden Trend area and Southeast Cana Woodford play;

· A decrease of approximately 9.4 Bcfe resulting from transfers to the proved developed producing category as a result of development drilling;

· A decrease of approximately 29.0 Bcfe due to revisions to previous estimates, primarily due to lower forecast natural gas prices at year-end 2012 which resulted in shorter economic lives on some undeveloped wells and caused others to become non-commercial; and

· A decrease of approximately 6.5 Bcfe due to the sale of our Barnett Shale assets in December 2012, which included four proved undeveloped locations.

We spent approximately $71.6 million of capital expenditures in 2012 to drill wells classified as proved undeveloped as of December 31, 2011. Our working interest in these wells at the time they were drilled was often significantly greater than our working interest as of December 31, 2011 because other working interest owners elected to not participate in the wells. As a result, the amount of reserves transferred into the proved developed producing category on account of wells drilled in 2012 was often significantly greater than the wells’ estimated proved undeveloped reserves as of December 31, 2011. In addition, the amount of reserves transferred into the proved developed producing category on account of wells drilled in 2012 was often different from the wells’ estimated proved undeveloped reserves as of December 31, 2011 because the performance of the wells differed from our original expectations.

Selected Financial Data, page 58

Non-GAAP Financial Measures, page 60

4. The introduction to your non-GAAP presentation indicates that you believe the measure “more accurately” reflects your ability to generate cash and “more accurately” describes the underlying performance of your operating assets. Explain to us why you believe use of the phrase “more accurately” does not result in giving greater prominence to your non-GAAP measure as compared to GAAP amounts. See Item 10(1)(i)(A) of Regulation S-K.

RESPONSE:

We acknowledge the Staff’s comments and respectfully note our belief that the prominence of other corresponding GAAP measures in the 2012 10-K, together with the other cautionary language around the use of non-GAAP measures, results in our not giving greater prominence to the non-GAAP measures than the GAAP measures. For example, the 2012 10-K discussion of Adjusted EBITDA is placed after the discussion of the other GAAP measures, including segment information. In addition, the reconciliation of Adjusted EBITDA to the nearest comparable GAAP measure on page 60 includes the following cautionary language:

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 under 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 U.S. GAAP.

Nonetheless, we propose to update the discussion of Adjusted EBITDA in the 2013 10-K to replace the phrase “more accurately” with “provides additional information” to lessen the chance that greater prominence is given to the non-GAAP measures.

Reconciliation of Adjusted EBITDA to net cash flows from operating activities and net income (loss), page 61

5. Disclosure under note (b) indicates that Adjusted EBITDA excludes “amortization” of commodity hedge costs. Explain to us the mechanism through which you are amortizing commodity hedge costs, and identify the specific authoritative literature that supports this accounting.

RESPONSE:

We acknowledge the Staff’s comment and respectfully note that the Partnership accounted for its commodity hedge costs, which included the costs of put premiums and costs incurred to reset commodity hedges to higher prices, in an effort to match the expense incurred in the same period the benefit was realized. The Partnership initially recorded the costs as an asset on its balance sheet. The value of this asset was held constant until the period in which the specific hedge transaction settled. During the settlement period of the hedge transaction, the asset was amortized as an expense each month. The Partnership believes this methodology appropriately matched the revenue and expense related to the transactions in the relevant period.

We recognize the alternative accounting treatment for the commodity hedge costs would be to expense the costs as part of our marked-to-market calculation, and that such treatment would have resulted in differences to the Partnership’s reported net income for years ended December 31, 2008, 2009 and 2010. The following table quantifies the differences in the Partnership’s reported net income / (loss) between the two methods:

($ in thousands)	Net Income (Loss) As Reported			Net Income (Loss) As Adjusted			Difference
2008	$	87,520		$	81,619		$	(5,901	)
2009	$	(171,258	)	$	(160,231	)	$	11,027
2010	$	(5,349	)	$	(1,392	)	$	3,957

In addition, we considered the following qualitative factors in comparing the differences in the results of the two methods:

1. Changes in earnings or trends were not masked. For two of the periods presented, the net loss we reported was actually greater.

2. The alternate methodology would not have moved the Partnership from a net income to a net loss position or vice versa.

3. While the reported net income / (loss) is different between the two methods, there would be no change to several of the Partnership’s key non-GAAP financial measures, including Adjusted EBITDA, distributable cash flow and distribution coverage ratio, as the differences result from non-cash items which are excluded as part of these calculations.

4. The Partnership’s compliance with its loan covenants or other contractual requirements was not impacted.

5. The amount of hedge cost amortization does not impact any of the goals by which management’s compensation is determined.

In summary, we believe that the Partnership’s presentation of the amortization of commodity hedge costs is reasonable in that it directly matches the expense to the associated revenues, and that adopting the alternative presentation of such costs would not materially alter an investor’s view of the Partnership’s financial results. Further mitigating the impact of the chosen accounting treatment is the fact that all commodity hedge costs were fully amortized as of the end of 2010, and the Partnership has not incurred any new commodity hedge costs since that time. Accordingly, we respectfully propose that no change be made to the presentation of commodity hedge costs in the 2012 10-K.

Quarterly Financial Information, page 62

6. The introductory sentence of the notes to your presentation of quarterly information describes the identified items as “unusual or infrequently occurring”. Given the nature of the items described, and the frequency with which the same or similar items have occurred, explain to us your basis for this description.

RESPONSE:

We acknowledge the Staff’s comment and respectfully note our belief that the description was appropriate on the grounds that the items described were either (a) out of the ordinary course of business, such as an acquisition, or (b) recurring, but subject to significant fluctuations in magnitude, such as commodity derivative gains. Our primary goal was to put investors on notice that factors such as the ones described could have material impacts on our results of operations, even though they may not be predictable.

Nonetheless, in order to avoid confusion in the future, we proposed to change the reference to “unusual or infrequently occurring” to “significant” in the 2013 10-K.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 64

Upstream Segment, page 79

7. We note your tabular disclosure of production for the periods shown on pages 79 and 90; however, it does not appear that you have provided disclosure here or elsewhere of the fields that that contain 15% or more of the Company’s total proved reserves. Please advise or revise your disclosure to comply with the requirements set forth in Item 1204(a) of Regulation S-K.

RESPONSE:

We acknowledge the Staff’s comment and respectfully note that one field, the Golden Trend Field, accounted for approximately 23% of the Partnership’s total proved reserves as of December 31, 2012. The production volumes for the Golden Trend Field for the years ended December 31, 2011 and 2012, which were mistakenly omitted from the 2012 10-K, were as follows:

	Year Ended December 31,
	2011	2012
Production Volumes:
Oil and condensate (Bbl)	213,936	283,284
Natural gas (Mcf)	1,941,749	2,966,796
NGLs (Bbl)	237,693	407,358

The Partnership did not acquire any interest in the Golden Trend Field until 2011.

We will include disclosure in the 2013 10-K as to the production volumes with respect to the Golden Trend Field (and any others that exceed 15% of the Partnership’s total proved reserves) as required by Item 1204(a) of Regulation S-K, and we propose that no change be made to the 2012 10-K

Notes to Consolidated Financial Statements, page F-9

Note 22 — Supplemental Oil and Gas Information (Unaudited), page F-47

Proved Reserves Summary, page F-48

8. You refer to reclassifying that portion of your reserves which are not considered to be commercial due to lower prices as “proved contingent resources.” We are not familiar with that term. We note that the term “proved contingent resources” is inconsistent with the nomenclature commonly accepted within the oil and gas industry such as that promulgated by the SPE/WPC/AAPG/SPEE in the Petroleum Resources Management System.

Please expand your glossary of oil and gas terms to include a definition of contingent resources and revise your disclosure to omit the reference to “proved” contingent resources.

RESPONSE:

We acknowledge the Staff’s comment, but respectfully note the following from the Petroleum Resources Management System (the “PRMS”). On page 2 of the PRMS, Figure 1-1 shows the Resources Classification Framework that introduces the concept of “Contingent Resources” and indicates that these are “sub-commercial” quantities. Figure 1-1 also shows that cumulative quantities of Contingent Resources can be further classified as “1C,” “2C” or “3C,” corresponding to the 1P/2P/3P designations used for Reserves. On page 3 of the PRMS, the definition of Contingent Resources is provided, and, consistent with Figure 1-1, it is noted that Contingent Resources may be categorized according to their level of certainty. The “level of certainty” concept is discussed in Section 2.2, “Resources Categorization,” of the PRMS, particularly in Section 2.2.2, “Category Definitions and Guidelines.”

While we acknowledge that the PRMS states that “no specific terms are defined for incremental quantities” within Contingent Resources, Section 2.2.2 of the PRMS states that applying the categories proved, probable and possible to Contingent Resources is permissible under the PRMS.

However, in order to minimize the risk of investor confusion in future filings, we propose to cease using the term “Proved Contingent Resources” in the 2013 10-K and the Partnership’s other filings in the future, but use “Contingent Resources” instead. In addition, beginning with the 2013 10-K, we propose to include therein the definition of Contingent Resources that is contained in the PRMS.

9. Please expand your disclosure of the changes in net quantities of proved reserves for the periods ending December 31, 2010 and December 31, 2011 to include an appropriate explanation of the significant changes to comply with FASB ASC paragraph 932-235-50-5.

RESPONSE:

We acknowledge the Staff’s comment and note that no disclosure regarding the changes in the Partnership’s proved reserves for the years ended December 31, 2010 and 2011 was included in the 2012 10-K as we believed that disclosure of the changes was not warranted. For 2010, the Partnership’s aggregate proved reserves did not materially change from the prior year, and we did not believe that any of the changes to Partnership’s proved reserves were significant. For 2011, the changes in the Partnership’s proved reserves resulted primarily from the Partnership’s mid-year acquisition of reserves in the acquisition of CC Energy II, L.L.C. (“Crow Creek Energy”), which was discussed extensively in the 2012 10-K. We also concluded that the magnitude of the changes in the other categories is insignificant compared to purchases of minerals in place related to the acquisition of Crow Creek Energy.

In the 2013 10-K and in the future, however, we propose to expand the discussion of the changes to the Partnership’s current and prior years’ reserves in the following manner:

Discussion of Changes to Estimated Quantities of Proved Reserves

The primary drivers behind the changes to our proved reserves in each of 2010, 2011 and 2012 are described in more detail below.

2010:

· Purchase of minerals in place were insignificant in 2010;

· extensions and discoveries were primarily related to drilling by other operators on assets in our Minerals Business which was sold in May 2010;

· sales of minerals in place were exclusively related to the sale of our Minerals Business in May 2010; and

· revisions to previous estimates were primarily the result of better than expected performance in our Big Escambia Creek Field and higher prices which extended the economic life and reserves of some wells, partially offset by poorer-than-expected performance in certain Permian and East Texas wells.

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;

· 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.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, page F-50

10. The disclosure on page F-51 and in Exhibit 99.1 refers to the inclusion of revenues associated with the sale of sulfur extracted to render certain of your proved natural gas reserves saleable. However, sulfur is not a hydrocarbon and therefore does not represent a “saleable hydrocarbon” as defined in Rule 4-10(a)(16) of Regulation S-X. Non-hydrocarbon revenues should not be included in the determination of economic producibility per Rule 4-10(a)(10) of Regulation S-X or in the computation of future cash inflows per FASB ASC paragraph 932-235-50-31.

Please revise your estimates of future cash inflows here and in Exhibit 99.1 to exclude the revenue derived from the sale of sulfur. Also revise the estimates of proved reserves in Exhibit 99.1 and throughout your filing to the extent required as a result of excluding the sulfur revenue.

RESPONSE:

We acknowledge the Staff’s comments and respectfully offer the following explanation. As described in the 2012 10-K, sulfur production is intimately connected with hydrocarbon production in several of the Partnership’s fields due to the fact that those fields have high concentrations of hydrogen sulfide which must be removed to render the hydrocarbons saleable. After removal , the hydrogen sulfide is further processed to convert it to elemental sulfur. The costs of refining the sulfur from the hydrogen sulfide are unrelated to the further processing and sale of the hydrocarbons, but those costs are inseparable from the total costs of operating the processing facilities.

The price the Partnership received for the elemental sulfur has varied significantly over the past several years. In some cases, prices were high enough that the Partnership experienced significant cash flows that positively impacted the value of the assets. During other periods, the cost to transport the sulfur to its sales point exceeded the sales price received for the sulfur, resulting in the Partnership incurring a net expense which negatively impacted the value of the assets.

Because the revenues derived from the sale of sulfur can be material, and because the Partnership cannot accurately isolate the costs associated with sulfur refinement, we believe the exclusion of only the sulfur revenues (while the costs are included) presents investors with an incomplete and inaccurate view of the quantity and value of the proved reserves of these fields. And, although we agree that sulfur is not a hydrocarbon, we believe the Partnership’s disclosure strikes an appropriate balance between the letter of the SMOG guidelines and their intent, and also with the intent of oil and gas reserves disclosure in general.

We have examined the impact of excluding the sulfur revenues on the Partnership’s proved reserves and the associated standardized measure as of December 31, 2012. We believe that the impact on total proved reserves is negligible, with the exclusion of sulfur revenues resulting in only a 0.9% reduction. The impact to standardized measure is more significant, however, with the exclusion of sulfur revenues reducing the standardized measure from $588.1 million to $519.9 million.

In light of these observations, we respectfully propose that the Partnership continue with its SMOG disclosure as presented in the 2012 10-K, and that the Partnership continue to explicitly disclose that sulfur revenues and costs are included. We further propose to include additional disclosures of how the SMOG value and proved reserves would be affected if the sulfur revenues were excluded in the 2013 10-K and in the future. We believe this presentation will provide investors the most meaningful and accurate information.

Exhibit 99.1

11. The reserves report does not include certain disclosures required by Item 1202(a)(8) of Regulation S-K. Please obtain and file a revised reserves report to include the following information in order to satisfy your filing obligations.

· The purpose for which the report was prepared, e.g., for inclusion as an exhibit in a filing made with the SEC (Item 1202(a)(8)(i)).

· The proportion of the Company’s total reserves covered by the report (Item 1202(a)(8)(iii)).

· The benchmark and average realized price relating to the natural gas liquids reserves included in the report as part of the primary economic assumptions (Item 1202(a)(8)(v)).

RESPONSE:

We acknowledge the Staff’s comment and have attached as Annex A hereto a revised reserves report that includes the additional information. Certain of this information was included elsewhere in the 2012 Form 10-K, including the benchmark price for natural gas liquids of $94.71 per barrel on page F-48 and the statement that all of the estimates of reserves were based on the estimates of the Partnership’s independent reserve engineer on page 22. Accordingly, we respectfully request the Staff’s concurrence that providing a report that includes the additional information for the year ended December 31, 2013 with the 2013 10-K will be sufficient, as opposed to re-filing the report for the year ended December 31, 2012.

12. The reserves report refers to additional supplemental information such as a Table of Contents, Appendix and Tables I and II that are not included in the reserves report. Please obtain and file a revised report to include the referenced supplemental information. Alternatively, remove these references if you do not intend to include this supplemental information in Exhibit 99.1. For additional information about the content

of the third party report, please refer to paragraph 3(e) on page 72 of section IV.B in the Adopting Release contained in the Modernization of Oil and Gas Reporting, Final Rule. The Adopting Release may be found at http://www.sec.gov/rules/final/2008/33-8995.pdf.

RESPONSE:

We acknowledge the Staff’s comment and note that the revised reserves report for the year ended December 31, 2012 attached as Annex A hereto removes the references to the supplemental information. We respectfully request the Staff’s concurrence that providing a report for the year ended December 31, 2013 that excludes the references to the supplemental information with the 2013 10-K will be sufficient, as opposed to re-filing the report for the year ended December 31, 2012.

* * * * *

In connection with the Staff’s comments and our responses, we confirm that (i) the Partnership is responsible for the adequacy and accuracy of the disclosure in the filing, (ii) the Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing and (iii) the Partnership may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please direct any questions that you have with respect to the foregoing and any request for additional supplemental information to Douglas E. McWilliams of Vinson & Elkins L.L.P. at (713) 758-3613.

	Very truly yours,

	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


	By:	/s/ Jeffrey P. Wood
	Name:	Jeffrey P. Wood
	Title:	Senior Vice President and Chief Financial Officer

Enclosures

cc: Jennifer O’Brien (Securities and Exchange Commission)

John Hodgin (Securities and Exchange Commission)

Charles C. Boettcher (Eagle Rock Energy Partners, L.P.)

Douglas E. McWilliams (Vinson & Elkins L.L.P.)

ANNEX A

See attached report from Cawley, Gillespie & Associates

dated January 8, 2014

Annex A

CAWLEY, GILLESPIE & ASSOCIATES, INC.

	PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

January 8, 2014

Mr. Steve Hendrickson

Sr. Vice President — Technical Evaluations

Eagle Rock Energy Partners, L.P.

1415 Louisiana Street, Suite 2700

Houston, TX 77002

	Re:	Evaluation Summary
		*Eagle Rock Energy Partners, L.P. Interests* Total Proved Reserves
		Certain Properties in Various States
		As of December 31, 2012

		Pursuant to the Guidelines of the
		Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Dear Mr. Hendrickson:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the interests located in certain properties in various states within the United States. This report, completed February 5, 2013 covers 100% of the proved reserves estimated for Eagle Rock Energy Partners, L.P. (“Eagle Rock”). This evaluation utilized an effective date of December 31, 2012, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). This report was prepared for the preparation of the Eagle Rock 2012 10K filing.

The proved reserves and economics for the Total Proved, Proved Developed and Proved Undeveloped are summarized as follows:

		Proved
		Total	Developed	Undeveloped
Net Reserves
Oil	- Mbbl	12,983.5	10,993.1	1,990.4
Gas	- MMcf	194,429.1	136,545.4	57,883.7
NGL	- Mbbl	12,866.5	10,445.2	2,421.4
Net Revenue
Oil	- M$	1,202,900.0	1,019,731.4	183,168.6
Gas	- M$	539,525.1	378,026.5	161,498.6
NGL	- M$	572,839.6	477,272.3	95,567.3
Exxon Retained	- M$	-43,315.1	-41,436.2	-1,878.9
Sulfur Revenue	- M$	136,317.0	132,655.7	3,661.3
Severance Taxes	- M$	159,650.7	138,093.2	21,557.5
Ad Valorem Taxes	- M$	18,609.7	17,274.4	1,335.2
Operating Expenses	- M$	510,875.2	463,729.0	47,146.2
Other Deductions	- M$	73,753.1	46,429.0	27,324.1
Investments	- M$	359,154.2	175,983.6	183,170.6
Net Operating Income (BFIT)	- M$	1,286,223.8	1,124,740.5	161,483.2
Discounted @ 10% (Present Worth)	- M$	588,114.9	576,517.3	11,597.6

The Proved Developed reserves are the summation of the PDP, PDNP and PDSI estimates. The Proved Developed reserves and economics, with a breakout of Proved Developed Producing, Proved Developed Non-Producing and Proved Developed Shut-In, are summarized as follows:

		Proved Developed
		Total	Producing	Non-Producing	Shut-In
Net Reserves
Oil	- Mbbl	10,993.1	10,277.5	715.6	0.0
Gas	- MMcf	136,545.4	126,618.1	9,927.3	0.0
NGL	- Mbbl	10,445.2	9,872.0	573.2	0.0
Net Revenue
Oil	- M$	1,019,731.4	954,631.8	65,099.6	0.0
Gas	- M$	378,026.5	351,284.0	26,742.5	0.0
NGL	- M$	477,272.3	450,784.3	26,488.0	0.0
Exxon Retained	- M$	-41,436.2	-41,436.2	0.0	0.0
Sulfur Revenue	- M$	132,655.7	132,621.8	34.0	0.0
Severance Taxes	- M$	138,093.2	130,726.6	7,366.6	0.0
Ad Valorem Taxes	- M$	17,274.4	15,771.3	1,503.1	0.0
Operating Expenses	- M$	463,729.0	447,819.8	15,810.6	98.6
Other Deductions	- M$	46,429.0	44,160.9	2,268.1	0.0
Investments	- M$	175,983.6	154,272.7	21,710.9	0.0
Net Operating Income (BFIT)	- M$	1,124,740.5	1,055,134.5	69,704.6	-98.6
Discounted @ 10% (Present Worth)	- M$	576,517.3	555,972.6	20,575.4	-30.7

Net revenue is prior to deducting state production taxes and Ad Valorem taxes. Future net cash flow is after deducting these taxes, future capital costs, operating expenses and other deductions, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Hydrocarbon Pricing

The base oil and gas prices calculated for December 31, 2012 were $94.71/bbl and $2.76/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price and NGL price are based upon WTI-Cushing oil spot prices during 2012 and the base gas price is based upon Henry Hub spot prices during 2012.

The base prices for oil, NGL and gas were adjusted for differentials, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the total proved properties were estimated to be $92.649 per barrel of oil, $2.775 per mcf of natural gas and $44.522 per barrel of natural gas liquids. All economic factors were held constant in accordance with SEC guidelines.

Exxon Retained Revenue

In certain properties and time periods, the future cash flow estimates in this reserve report include a reduction to future revenues due to a “Retained Revenue Interest” owned by ExxonMobil. These interests were retained by ExxonMobil at the time they sold them to Eagle Rock’s predecessors, and remain in effect. In general, these interests require Eagle Rock to make payments of a percentage of the revenues received over a Base Price from the sale of oil, natural gas and/or natural gas liquids production. Except for severance taxes, the interests are free of operating and capital expenses. The effect of the interest has been treated as a reduction to the revenues that Eagle Rock will derive from the sale of its reserves. An Exxon Retained section is included that contains only the revenue from the Retained Revenue Interest.

The Retained Revenue Interest does not necessarily apply to all of the interest that Eagle Rock owns in the wells that are subject to the interest, nor does it necessarily apply to all of the wells in the fields in which the subject wells are located. This is due to the fact that Eagle Rock’s predecessors did not acquire all of the interest that Eagle Rock now owns from ExxonMobil. The portions of Eagle Rock’s ownership that was acquired from other parties are not subject to the Retained Revenue Interest.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 135 proved undeveloped (“PUD”) locations based in various fields throughout the United States. Each of these drilling locations proposed as part of Eagle Rock’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Eagle Rock has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, Eagle Rock has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.

Reserve Estimation Methods

Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy. In the Big Escambia Creek and Flomaton fields in Alabama, Eagle Rock’s pentane volumes are shown separately in the plant statements and are not tracked in public records. Therefore, these volumes were added to the condensate yield in this report to properly match the company’s sales volumes.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Eagle Rock properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Economic Parameters

Ownership information, economic factors such as liquid and gas prices, price differentials, expenses, investments and tax rates were furnished by Eagle Rock and were accepted as furnished.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging at abandonment has been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. We do not own an interest in the properties or Eagle Rock Energy Partners, L.P. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

	Yours very truly,

	Robert D. Ravnaas, P.E.
	President
	Cawley, Gillespie & Associates
	Texas Registered Engineering Firm F-693

Table I - TP

Composite Reserve Estimates and Economic Forecasts
Eagle Rock Energy Partners, L.P. Interests
Certain Properties in Various States
Total Proved Reserves
As of December 31, 2012

(1)

End

(2)
Gross Oil
Production

(3)
Gross Gas
Production

(4)
Gross NGL
Production

(5)
Net Oil
Production

(6)
Net Gas
Sales

(7)
Net NGL
Production

(8)
Avg Oil
Price

(9)
Avg Gas
Price

(10)
Avg NGL
Price

Mo-Year

MBBLS

MMCF

MBBLS

MMCF

MBBLS

$/BBL

$/MCF

$/BBL

12-2013

2,542.5

116,737.1

2,700.4

1,176.634

12,533.404

975.030

-1.567

93.143

1.010

2.787

0.480

45.492

12-2014

2,516.2

122,885.9

2,958.3

1,078.900

14,023.597

929.771

-1.655

93.055

1.009

2.784

0.476

45.121

12-2015

2,329.2

123,581.3

3,084.6

956.379

14,335.357

878.602

-1.694

93.016

1.007

2.778

0.474

44.906

12-2016

2,081.6

108,960.5

2,731.3

883.814

12,834.767

814.357

-1.805

92.905

1.008

2.782

0.475

44.993

12-2017

1,775.6

96,851.2

2,472.8

793.391

11,396.844

760.406

-1.812

92.898

1.007

2.778

0.475

45.007

12-2018

1,604.7

87,919.6

2,271.9

746.737

10,281.311

699.354

-1.904

92.806

1.007

2.778

0.476

45.052

12-2019

1,416.1

77,136.0

1,964.9

662.606

9,151.885

621.880

-1.925

92.785

1.006

2.777

0.478

45.280

12-2020

1,275.6

70,012.1

1,765.4

598.460

8,306.018

560.815

-1.992

92.718

1.006

2.776

0.479

45.383

12-2021

1,166.8

63,705.6

1,604.5

548.448

7,547.428

510.483

-2.023

92.687

1.006

2.777

0.480

45.414

12-2022

1,064.9

58,471.9

1,475.1

499.601

6,962.366

468.949

-2.025

92.685

1.005

2.775

0.480

45.429

12-2023

978.1

53,732.7

1,366.0

459.847

6,441.339

430.867

-2.019

92.691

1.005

2.775

0.480

45.483

12-2024

891.8

49,845.7

1,267.8

417.068

6,030.702

397.560

-2.145

92.565

1.004

2.772

0.478

45.294

12-2025

804.3

45,380.3

1,178.1

370.546

5,612.195

365.751

-2.404

92.306

1.004

2.770

0.474

44.910

12-2026

746.3

42,112.0

1,104.4

343.312

5,230.206

339.031

-2.409

92.301

1.004

2.770

0.474

44.901

12-2027

690.9

39,197.1

1,036.8

318.344

4,893.106

316.056

-2.417

92.293

1.004

2.770

0.474

44.865

12-2028

645.2

36,669.6

978.0

296.805

4,596.470

297.289

-2.422

92.288

1.004

2.770

0.473

44.808

12-2029

600.2

33,999.4

917.1

275.681

4,283.844

278.616

-2.421

92.289

1.004

2.770

0.472

44.749

12-2030

565.8

31,606.7

872.1

256.099

4,034.103

262.591

-2.438

92.272

1.006

2.777

0.470

44.510

12-2031

523.5

29,578.0

824.0

237.036

3,807.533

249.515

92.300

2.775

44.418

S Tot

24,219.5

1,288,382.7

32,573.6

10,919.706

152,302.474

10,156.922

92.770

2.777

45.114

After

4,952.8

297,518.4

9,992.6

2,063.758

42,126.665

2,709.605

92.007

2.766

42.300

Total

29,172.3

1,585,901.2

42,566.2

12,983.465

194,429.138

12,866.528

92.649

2.775

44.522

Cum

194,193.1

4,938,903.6

5,489.8

Ult

223,365.4

6,524,804.8

48,056.0

(12)

(13)

(14)

(15)

(16)

(17)

(18)

(19)

(11)

Oil

Gas

NGL

Exxon

Sulfur

Total

Production

Ad Valorem

(20)

End

Revenue

Retained

Revenue

Taxes

$/BOE6

Mo-Year

12-2013

109,594.669

34,925.517

44,355.851

-7,876.516

13,071.932

194,071.453

13,379.004

1,531.704

6.847

12-2014

100,397.574

39,039.749

41,951.968

-7,255.249

11,980.493

186,114.534

12,303.104

1,370.493

6.606

12-2015

88,958.263

39,821.137

39,454.167

-6,646.337

10,964.328

172,551.558

11,372.192

1,285.498

6.781

12-2016

82,110.704

35,699.907

36,640.767

-6,108.702

10,081.459

158,424.135

10,539.712

1,207.576

7.262

12-2017

73,704.494

31,658.793

34,223.594

-5,587.720

9,229.975

143,229.135

9,576.150

1,155.772

7.844

12-2018

69,301.401

28,562.047

31,507.566

-5,129.197

8,477.765

132,719.582

8,886.772

1,100.224

8.341

12-2019

61,479.549

25,412.167

28,158.769

-4,711.330

7,788.469

118,127.625

7,936.873

996.529

9.081

12-2020

55,488.299

23,053.381

25,451.636

0.000

7,170.385

111,163.702

7,579.352

886.969

9.677

12-2021

50,833.881

20,957.834

23,182.865

0.000

6,581.295

101,555.877

6,939.176

801.370

10.395

12-2022

46,305.595

19,319.223

21,303.789

0.000

6,001.460

92,930.068

6,346.657

724.464

11.015

12-2023

42,623.770

17,874.510

19,597.328

0.000

5,324.133

85,419.742

5,832.982

645.241

11.573

12-2024

38,605.801

16,718.231

18,007.168

0.000

4,879.769

78,210.969

5,301.242

599.184

11.858

12-2025

34,203.626

15,547.262

16,425.728

0.000

3,983.468

70,160.084

4,684.403

530.529

11.732

12-2026

31,687.909

14,488.839

15,222.848

0.000

3,668.621

65,068.217

4,339.543

492.490

12.464

12-2027

29,380.975

13,553.172

14,179.702

0.000

3,387.750

60,501.598

4,030.760

455.889

13.157

12-2028

27,391.591

12,731.263

13,320.825

0.000

3,139.023

56,582.703

3,767.565

424.386

13.803

12-2029

25,442.362

11,867.706

12,467.894

0.000

2,894.635

52,672.598

3,505.331

394.593

14.544

12-2030

23,630.738

11,204.237

11,687.867

0.000

2,580.726

49,103.569

3,259.374

366.315

15.187

12-2031

21,878.498

10,567.383

11,082.931

0.000

2,376.466

45,905.278

3,047.981

336.565

15.931

S Tot

1,013,019.701

423,002.360

458,223.265

-43,315.052

123,582.153

1,974,512.428

132,628.173

15,305.789

9.489

After

189,880.310

116,522.719

114,616.343

0.000

12,734.877

433,754.249

27,022.556

3,303.880

16.367

Total

1,202,900.011

539,525.079

572,839.608

-43,315.052

136,317.030

2,408,266.677

159,650.730

18,609.669

10.876

(22)

(23)

(24)

(25)

(26)

(27)

(29)

(30)

(31)

(21)

Operating

Wells

Workover

3rd Party

Other

(28)

Future Net

Cumulative

Cum.Cash Flow

End

Expense

Gross

Net

Expense

COPAS

Deductions

Investment

Cash Flow

Disc.@ 10.%

Mo-Year

Count

12-2013

22,081.236

1751

593.6

0.000

4,617.659

51,131.634

101,330.217

95,922.391

12-2014

21,012.554

1301

501.4

0.000

5,546.365

78,350.629

67,531.389

168,861.606

153,304.872

12-2015

20,872.191

1285

489.3

0.000

5,687.189

94,270.937

39,063.551

207,925.157

183,197.767

12-2016

20,740.896

1261

488.0

0.000

5,054.606

24,172.437

96,708.908

304,634.065

251,392.841

12-2017

20,580.526

1211

461.3

0.000

4,418.535

27,507.655

79,990.498

384,624.564

302,738.605

12-2018

20,362.872

1177

454.6

0.000

3,948.978

12,910.250

85,510.486

470,135.050

352,593.190

12-2019

20,045.758

1123

431.2

0.000

3,493.439

3,500.281

82,154.744

552,289.794

395,668.151

12-2020

19,548.235

1094

424.0

0.000

3,167.269

4,467.468

75,514.408

627,804.202

431,536.778

12-2021

19,344.709

1058

409.3

0.000

2,881.169

2,606.025

68,983.428

696,787.630

461,165.608

12-2022

18,975.037

1026

400.9

0.000

2,666.588

2,744.959

61,472.364

758,259.994

485,074.745

12-2023

18,524.422

971

380.2

0.000

2,462.444

3,506.942

54,447.711

812,707.705

504,264.146

12-2024

17,659.463

947

372.5

0.000

2,268.304

2,742.130

49,640.646

862,348.351

520,093.734

12-2025

16,063.756

912

359.6

0.000

2,046.518

2,005.295

44,829.584

907,177.934

533,020.709

12-2026

15,970.930

890

357.4

0.000

1,919.180

2,067.190

40,278.884

947,456.819

543,541.192

12-2027

15,818.553

861

349.3

0.000

1,802.825

1,536.148

36,857.423

984,314.242

552,252.379

12-2028

15,642.919

835

338.4

0.000

1,695.566

2,764.359

32,287.909

1,016,602.151

559,173.042

12-2029

15,443.869

809

333.5

0.000

1,584.035

6,346.174

25,398.596

1,042,000.747

564,137.390

12-2030

15,207.016

776

321.4

0.000

1,485.836

13,871.206

14,913.821

1,056,914.568

566,854.172

12-2031

15,074.054

758

313.0

0.000

1,395.467

536.164

25,515.047

1,082,429.615

570,904.907

S Tot

348,968.998

0.000

58,141.969

337,037.882

1,082,429.615

570,904.907

After

161,906.236

0.000

15,611.093

22,116.347

203,794.137

1,286,223.752

588,114.913

Total

510,875.234

0.000

73,753.062

359,154.229

1,286,223.752

588,114.913

SEC Pricing (12-31-2012)

Percent

Cum. Disc.

WTI Cushing

Henry Hub

.00

1,286,223.752

Year

Oil $/STB

Gas $/MMBTU

5.00

822,638.226

2011

94.71

2.76

9.00

624,889.490

Thereafter

FLAT

10.00

588,114.913

Cap

94.71

2.76

12.00

525,038.813

15.00

450,372.448

Expenses and investments provided by Eagle Rock Energy

12 Months in first year 49.999 Year Life (12/2062)

THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.

TEXAS REGISTERED ENGINEERING FIRM F-693.

Cawley, Gillespie & Associates, Inc.

Table I - PDP

Composite Reserve Estimates and Economic Forecasts
Eagle Rock Energy Partners, L.P. Interests
Certain Properties in Various States
Proved Developed Producing Reserves
As of December 31, 2012

(1)

End

(2)

Gross Oil
Production

(3)

Gross Gas
Production

(4)

Gross NGL
Production

(5)

Net Oil
Production

(6)

Net Gas
Sales

(7)

Net NGL
Production

(8)

Avg Oil
Price

(9)

Avg Gas
Price

(10)

Avg NGL
Price

Mo-Year

MBBLS

MMCF

MBBLS

MMCF

MBBLS

$/BBL

$/MCF

$/BBL

12-2013

2,260.6

111,230.8

2,439.9

1,047.164

12,022.464

919.072

-1.565

93.145

1.007

2.780

0.480

45.440

12-2014

1,857.6

94,009.6

2,002.4

880.160

9,925.273

776.234

-1.518

93.192

1.008

2.781

0.485

45.960

12-2015

1,611.3

82,979.2

1,745.8

774.327

8,687.883

684.159

-1.511

93.199

1.007

2.780

0.488

46.230

12-2016

1,434.1

74,584.4

1,564.3

695.316

7,755.337

617.462

-1.518

93.192

1.008

2.781

0.490

46.364

12-2017

1,282.7

67,198.6

1,406.7

625.866

6,988.351

559.402

-1.519

93.191

1.008

2.781

0.490

46.417

12-2018

1,161.1

61,265.0

1,285.0

566.718

6,350.510

510.860

-1.545

93.165

1.007

2.780

0.491

46.467

12-2019

1,058.1

55,305.1

1,179.4

517.402

5,807.332

466.907

-1.584

93.126

1.007

2.780

0.491

46.509

12-2020

962.7

50,900.3

1,085.6

469.884

5,340.196

424.975

-1.658

93.052

1.007

2.780

0.492

46.571

12-2021

879.2

46,849.9

1,001.1

428.647

4,918.510

389.476

-1.682

93.028

1.007

2.780

0.492

46.571

12-2022

809.3

43,170.2

929.8

395.439

4,538.294

361.001

-1.697

93.013

1.007

2.780

0.491

46.541

12-2023

738.6

39,687.1

862.7

363.137

4,224.517

331.414

-1.698

93.012

1.007

2.779

0.492

46.627

12-2024

675.9

36,877.3

805.8

330.648

3,958.354

307.695

-1.857

92.853

1.006

2.777

0.490

46.417

12-2025

607.1

33,345.5

743.8

293.079

3,670.841

281.106

-2.172

92.538

1.005

2.774

0.487

46.118

12-2026

565.5

31,067.4

699.0

272.447

3,431.201

260.564

-2.184

92.526

1.005

2.773

0.487

46.122

12-2027

526.5

28,955.8

656.8

253.925

3,211.499

243.021

-2.196

92.514

1.004

2.772

0.487

46.095

12-2028

492.2

27,050.7

620.2

237.274

3,034.302

229.345

-2.202

92.508

1.004

2.771

0.486

46.019

12-2029

457.8

25,021.3

580.7

220.730

2,832.262

215.176

-2.204

92.506

1.004

2.771

0.485

45.951

12-2030

426.8

23,096.9

543.7

205.640

2,649.323

201.305

-2.209

92.501

1.004

2.772

0.485

45.917

12-2031

398.3

21,511.0

511.1

192.472

2,480.653

189.505

92.493

2.772

45.850

S Tot

18,205.3

954,105.9

20,663.8

8,770.276

101,827.102

7,968.678

93.008

2.778

46.198

After

3,362.7

186,377.8

5,471.9

1,507.180

24,791.008

1,903.320

92.175

2.758

43.422

Total

21,568.0

1,140,483.8

26,135.8

10,277.456

126,618.109

9,871.998

92.886

2.774

45.663

Cum

187,139.7

4,833,555.4

5,489.8

Ult

208,707.7

5,974,039.2

31,625.6

(12)

(13)

(14)

(15)

(16)

(17)

(18)

(19)

(11)

Oil

Gas

NGL

Exxon

Sulfur

Total

Production

Ad Valorem

(20)

End

Revenue

Retained

Revenue

Taxes

$/BOE6

Mo-Year

12-2013

97,538.100

33,417.644

41,762.738

-7,550.104

12,683.458

177,851.835

12,563.151

1,509.651

7.196

12-2014

82,024.234

27,598.506

35,675.412

-6,919.747

11,579.031

149,957.436

10,672.540

1,325.678

7.881

12-2015

72,166.561

24,154.326

31,628.805

-6,346.139

10,602.987

132,206.539

9,442.583

1,185.646

8.603

12-2016

64,798.193

21,564.518

28,627.813

-5,839.411

9,754.993

118,906.107

8,510.164

1,070.759

9.273

12-2017

58,325.336

19,432.585

25,965.946

-5,347.483

8,929.867

107,306.251

7,690.021

963.899

9.952

12-2018

52,798.180

17,657.444

23,738.247

-4,914.266

8,208.395

97,488.000

6,991.895

874.210

10.614

12-2019

48,183.736

16,141.779

21,715.484

-4,519.047

7,546.616

89,068.567

6,386.271

798.608

11.310

12-2020

43,723.679

14,845.411

19,791.587

0.000

6,952.615

85,313.292

6,194.918

709.127

11.948

12-2021

39,876.210

13,672.785

18,138.244

0.000

6,386.235

78,073.473

5,668.777

645.334

12.773

12-2022

36,780.845

12,617.721

16,801.408

0.000

5,826.198

72,026.172

5,227.170

586.219

13.469

12-2023

33,776.271

11,740.951

15,452.993

0.000

5,166.631

66,136.846

4,793.360

521.625

14.098

12-2024

30,701.740

10,993.624

14,282.368

0.000

4,737.835

60,715.567

4,369.954

487.415

14.378

12-2025

27,121.033

10,184.324

12,963.988

0.000

3,856.242

54,125.586

3,837.603

429.381

14.185

12-2026

25,208.316

9,514.933

12,017.746

0.000

3,554.234

50,295.230

3,560.981

400.380

15.064

12-2027

23,491.709

8,903.483

11,202.067

0.000

3,285.459

46,882.718

3,316.443

373.817

15.947

12-2028

21,949.706

8,408.797

10,554.267

0.000

3,046.930

43,959.701

3,108.056

348.769

16.712

12-2029

20,418.831

7,848.183

9,887.630

0.000

2,811.984

40,966.628

2,895.070

324.525

17.616

12-2030

19,021.842

7,342.894

9,243.386

0.000

2,580.726

38,188.848

2,696.773

301.358

18.529

12-2031

17,802.359

6,877.441

8,688.798

0.000

2,376.466

35,745.065

2,522.469

280.760

19.528

S Tot

815,706.882

282,917.350

368,138.926

-41,436.197

119,886.901

1,545,213.861

110,448.198

13,137.163

11.461

After

138,924.966

68,366.684

82,645.408

0.000

12,734.877

302,671.935

20,278.404

2,634.138

20.011

Total

954,631.847

351,284.034

450,784.334

-41,436.197

132,621.778

1,847,885.796

130,726.602

15,771.301

13.016

(22)

(23)

(24)

(25)

(26)

(27)

(29)

(30)

(31)

(21)

Operating

Wells

Workover

3rd Party

Other

(28)

Future Net

Cumulative

Cum.Cash Flow

End

Expense

Gross

Net

Expense

COPAS

Deductions

Investment

Cash Flow

Disc.@ 10. %

Mo-Year

Count

12-2013

21,837.075

1715

580.2

0.000

4,416.534

9,253.386

128,272.038

122,359.986

12-2014

20,386.442

1197

459.2

0.000

3,562.324

16,123.820

97,886.633

226,158.671

206,790.003

12-2015

19,851.948

1130

417.0

0.000

3,092.980

46,158.795

52,474.587

278,633.258

247,654.480

12-2016

19,405.611

1078

401.9

0.000

2,748.724

3,897.818

83,273.030

361,906.288

306,595.213

12-2017

18,964.710

1006

363.3

0.000

2,472.851

3,190.403

74,024.367

435,930.655

353,978.901

12-2018

18,519.018

969

353.7

0.000

2,254.723

12,368.450

56,479.704

492,410.359

386,999.594

12-2019

18,164.048

912

326.3

0.000

2,067.201

2,700.281

58,952.158

551,362.517

417,917.989

12-2020

17,635.888

876

314.9

0.000

1,913.617

3,381.944

55,477.798

606,840.315

444,291.234

12-2021

17,412.709

843

300.5

0.000

1,767.332

2,404.238

50,175.083

657,015.397

465,844.893

12-2022

17,029.932

811

290.8

0.000

1,643.816

2,198.548

45,340.488

702,355.885

483,487.936

12-2023

16,559.596

756

269.4

0.000

1,523.639

3,218.942

39,519.683

741,875.568

497,428.266

12-2024

15,718.331

730

259.2

0.000

1,397.380

2,350.857

36,391.630

778,267.198

509,038.649

12-2025

14,176.104

701

250.8

0.000

1,251.519

1,701.295

32,729.685

810,996.883

518,480.292

12-2026

14,093.663

680

247.6

0.000

1,176.609

1,643.904

29,419.692

840,416.576

526,164.081

12-2027

13,998.889

658

241.7

0.000

1,105.412

1,536.148

26,552.009

866,968.585

532,440.276

12-2028

13,866.002

637

234.7

0.000

1,042.470

2,764.359

22,830.044

889,798.629

537,338.372

12-2029

13,695.852

614

230.6

0.000

971.786

6,221.174

16,858.220

906,656.849

540,648.775

12-2030

13,507.315

585

221.2

0.000

909.135

13,337.456

7,436.810

914,093.659

542,056.006

12-2031

13,387.525

567

212.4

0.000

850.220

164.188

18,539.904

932,633.563

544,998.476

S Tot

318,210.660

0.000

36,168.270

134,616.006

932,633.563

544,998.476

After

129,609.119

0.000

7,992.580

19,656.711

122,500.983

1,055,134.545

555,972.580

Total

447,819.779

0.000

44,160.852

154,272.717

1,055,134.545

555,972.580

SEC Pricing (12-31-2012)

Percent

Cum. Disc.

WTI Cushing

Henry Hub

.00

1,055,134.545

Year

Oil $/STB

Gas $/MMBTU

5.00

730,236.990

2011

94.71

2.76

9.00

583,874.276

Thereafter

FLAT

10.00

555,972.580

Cap

94.71

2.76

12.00

507,520.644

15.00

449,049.721

Expenses and investments provided by Eagle Rock Energy

12 Months in first year 49.999 Year Life (12/2062)

THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.

TEXAS REGISTERED ENGINEERING FIRM F-693.

Cawley, Gillespie & Associates, Inc.

Table I - PDNP

Composite Reserve Estimates and Economic Forecasts
Eagle Rock Energy Partners, L.P. Interests
Certain Properties in Various States
Proved Developed Non-Producing Reserves
As of December 31, 2012

(1)
End

(2)
Gross Oil
Production

(3)
Gross Gas
Production

(4)
Gross NGL
Production

(5)
Net Oil
Production

(6)
Net Gas Sales

(7)
Net NGL
Production

(8)
Avg Oil
Price

(9)
Avg Gas
Price

(10)
Avg NGL
Price

Mo-Year

MBBLS

MMCF

MBBLS

MMCF

MBBLS

$/BBL

$/MCF

$/BBL

12-2013

35.2

802.6

42.9

16.383

80.518

13.601

-2.843

91.867

1.078

2.974

0.549

52.020

12-2014

58.2

1,170.0

38.4

25.209

207.245

15.130

-3.432

91.278

1.040

2.870

0.548

51.913

12-2015

57.4

1,670.7

60.6

27.888

491.650

22.149

-3.841

90.869

0.963

2.658

0.530

50.190

12-2016

65.7

2,078.5

61.0

31.121

678.818

26.207

-4.057

90.653

0.955

2.635

0.526

49.839

12-2017

72.9

2,187.5

61.7

38.671

645.618

30.934

-3.726

90.984

0.960

2.650

0.519

49.147

12-2018

58.9

1,895.5

53.3

35.910

549.061

26.859

-3.865

90.845

0.964

2.660

0.521

49.318

12-2019

55.6

1,814.6

47.2

34.793

534.565

23.845

-4.037

90.673

0.968

2.671

0.522

49.474

12-2020

57.2

1,769.4

47.4

35.746

513.021

23.732

-4.107

90.603

0.963

2.658

0.514

48.712

12-2021

65.1

1,470.9

46.6

39.329

442.670

22.664

-4.021

90.689

0.971

2.680

0.510

48.266

12-2022

57.2

1,360.8

43.7

34.412

443.298

20.583

-4.053

90.657

0.962

2.656

0.510

48.325

12-2023

59.7

1,247.7

44.9

34.840

397.606

20.511

-3.816

90.894

0.967

2.670

0.503

47.677

12-2024

51.0

1,074.9

37.6

29.796

377.696

17.103

-3.931

90.779

0.960

2.650

0.500

47.365

12-2025

45.4

964.2

40.3

25.502

359.732

17.408

-4.087

90.623

0.963

2.657

0.468

44.370

12-2026

40.4

831.4

36.4

22.723

313.372

15.763

-4.096

90.614

0.965

2.664

0.470

44.476

12-2027

33.7

733.1

32.6

19.574

281.197

14.258

-4.210

90.500

0.965

2.663

0.470

44.491

12-2028

29.9

626.0

28.8

17.470

235.853

12.508

-4.289

90.421

0.966

2.665

0.473

44.786

12-2029

26.7

544.6

26.1

15.599

203.881

11.316

-4.314

90.396

0.967

2.668

0.475

44.981

12-2030

34.0

641.7

37.5

16.055

214.296

14.092

-4.210

90.500

1.023

2.823

0.460

43.554

12-2031

25.9

617.5

37.0

12.050

218.200

15.308

90.751

2.776

43.161

S Tot

929.9

23,501.5

824.2

513.071

7,188.296

363.973

90.770

2.677

47.860

After

421.3

9,406.2

581.5

202.555

2,739.042

209.196

91.473

2.739

43.349

Total

1,351.3

32,907.8

1,405.7

715.626

9,927.338

573.170

90.969

2.694

46.213

Cum

1,461.8

77,629.0

Ult

2,813.1

110,536.7

1,405.7

(11)
End

(12)
Oil
Revenue

(13)
Gas
Revenue

(14)
NGL
Revenue

(15)
Exxon
Retained

(16)
Sulfur
Revenue

(17)
Total
Revenue

(18)
Production
Taxes

(19)
Ad Valorem
Taxes

(20)
$/BOE6

Mo-Year

12-2013

1,505.023

239.424

707.552

0.000

2,451.999

188.076

22.052

5.117

12-2014

2,301.002

594.733

785.464

0.000

3,681.199

254.060

36.641

3.684

12-2015

2,534.187

1,306.893

1,111.676

0.000

4,952.757

302.146

60.391

3.558

12-2016

2,821.179

1,788.901

1,306.136

0.000

0.390

5,916.606

352.895

78.357

3.684

12-2017

3,518.472

1,710.672

1,520.343

0.000

7.463

6,756.950

407.759

123.405

4.117

12-2018

3,262.285

1,460.729

1,324.607

0.000

5.971

6,053.592

366.730

110.027

4.670

12-2019

3,154.759

1,427.785

1,179.691

0.000

4.778

5,767.013

346.004

102.161

5.121

12-2020

3,238.709

1,363.852

1,156.038

0.000

3.832

5,762.432

343.465

96.634

5.360

12-2021

3,566.716

1,186.145

1,093.928

0.000

3.057

5,849.846

359.939

85.430

5.729

12-2022

3,119.693

1,177.491

994.664

0.000

2.446

5,294.293

319.964

75.451

6.154

12-2023

3,166.743

1,061.548

977.901

0.000

1.957

5,208.148

323.074

66.975

6.633

12-2024

2,704.883

1,000.979

810.064

0.000

1.570

4,517.496

272.052

59.992

6.970

12-2025

2,311.029

955.655

772.393

0.000

1.252

4,040.329

239.052

53.672

6.676

12-2026

2,059.000

834.911

701.073

0.000

1.002

3,595.986

213.587

48.148

7.357

12-2027

1,771.422

748.816

634.376

0.000

0.238

3,154.851

186.659

41.131

7.431

12-2028

1,579.641

628.476

560.203

0.000

2,768.320

163.725

37.212

7.848

12-2029

1,410.119

543.862

509.009

0.000

2,462.991

146.190

34.105

8.393

12-2030

1,452.934

604.908

613.763

0.000

2,671.606

163.158

31.078

7.592

12-2031

1,093.584

605.714

660.730

0.000

2,360.028

147.787

23.810

7.644

S Tot

46,571.380

19,241.495

17,419.612

0.000

33.956

83,266.442

5,096.321

1,186.673

5.644

After

18,528.184

7,500.977

9,068.382

0.000

35,097.544

2,270.266

316.456

8.912

Total

65,099.564

26,742.472

26,487.994

0.000

33.956

118,363.986

7,366.587

1,503.129

6.591

(22)

(23)

(24)

(25)

(26)

(27)

(29)

(30)

(31)

(21)

Operating

Wells

Workover

3rd Party

Other

(28)

Future Net

Cumulative

Cum.Cash Flow

End

Expense

Gross

Net

Expense

COPAS

Deductions

Investment

Cash Flow

Disc.@ 10. %

Mo-Year

Count

12-2013

133.378

7.1

0.000

64.350

2,005.462

38.681

-26.735

12-2014

171.461

17.6

0.000

84.894

2,370.359

763.784

802.464

601.800

12-2015

299.751

38.4

0.000

142.227

5,625.153

-1,476.911

-674.446

-567.394

12-2016

400.750

46.4

0.000

193.390

2,692.496

2,198.717

1,524.271

996.495

12-2017

508.373

49.1

0.000

176.630

945.000

4,595.784

6,120.054

3,923.873

12-2018

525.633

52.0

0.000

150.983

541.800

4,358.420

10,478.474

6,448.202

12-2019

565.013

56.0

0.000

148.805

800.000

3,805.030

14,283.504

8,429.822

12-2020

595.650

60.3

0.000

136.929

1,085.524

3,504.231

17,787.735

10,078.468

12-2021

615.302

59.9

0.000

117.045

201.787

4,470.342

22,258.077

11,995.158

12-2022

633.167

61.3

0.000

115.634

546.411

3,603.666

25,861.743

13,388.950

12-2023

656.104

61.9

0.000

102.944

288.000

3,771.052

29,632.795

14,711.689

12-2024

632.409

64.5

0.000

91.509

391.273

3,070.262

32,703.057

15,688.787

12-2025

578.930

60.0

0.000

67.086

304.000

2,797.588

35,500.645

16,492.388

12-2026

568.883

61.0

0.000

57.904

423.286

2,284.178

37,784.823

17,091.281

12-2027

511.488

58.8

0.000

51.132

.000

2,364.440

40,149.263

17,650.306

12-2028

469.234

54.9

0.000

40.175

.000

2,057.974

42,207.237

18,090.555

12-2029

443.945

54.2

0.000

33.914

125.000

1,679.837

43,887.075

18,416.684

12-2030

428.295

52.2

0.000

34.260

533.750

1,481.065

45,368.139

18,675.725

12-2031

415.123

52.5

0.000

31.048

371.976

1,370.284

46,738.423

18,895.025

S Tot

9,152.889

0.000

1,840.858

19,251.277

46,738.423

18,895.025

After

6,657.756

0.000

427.272

2,459.636

22,966.159

69,704.582

20,575.411

Total

15,810.645

0.000

2,268.130

21,710.913

69,704.582

20,575.411

SEC Pricing (12-31-2012)

Percent

Cum. Disc.

WTI Cushing

Henry Hub

.00

69,704.582

Year

Oil $/STB

Gas $/MMBTU

5.00

35,042.475

2011

94.71

2.76

9.00

22,694.576

Thereafter

FLAT

10.00

20,575.411

Cap

94.71

2.76

12.00

17,076.758

15.00

13,168.091

Expenses and investments provided by Eagle Rock Energy

12 Months in first year 49.999 Year Life (12/2062)

THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.

TEXAS REGISTERED ENGINEERING FIRM F-693.

Cawley, Gillespie & Associates, Inc.

Table I - Shut-In

Composite Reserve Estimates and Economic Forecasts
Eagle Rock Energy Partners, L.P. Interests
Certain Properties in Various States
Proved Shut-In Reserves
As of December 31, 2012

(1)

End

(2)
Gross Oil
Production

(3)
Gross Gas
Production

(4)
Gross NGL
Production

(5)
Net Oil
Production

(6)
Net Gas
Sales

(7)
Net NGL
Production

(8)
Avg Oil
Price

(9)
Avg Gas
Price

(10)
Avg NGL
Price

Mo-Year

MBBLS

MMCF

MBBLS

MMCF

MBBLS

$/BBL

$/MCF

$/BBL

12-2013

.000

12-2014

.000

12-2015

.000

12-2016

.000

12-2017

.000

12-2018

.000

12-2019

.000

12-2020

.000

12-2021

.000

12-2022

.000

12-2023

.000

12-2024

.000

12-2025

.000

12-2026

.000

12-2027

.000

12-2028

.000

12-2029

.000

12-2030

.000

12-2031

.000

S Tot

.000

After

.000

Total

.000

Cum

4,219.8

1,445.7

Ult

4,219.8

1,445.7

(12)

(13)

(14)

(15)

(16)

(17)

(18)

(19)

(11)

Oil

Gas

NGL

Exxon

Sulfur

Total

Production

Ad Valorem

(20)

End

Revenue

Retained

Revenue

Taxes

$/BOE6

Mo-Year

12-2013

.000

0.000

.000

12-2014

.000

0.000

.000

12-2015

.000

0.000

.000

12-2016

.000

0.000

.000

12-2017

.000

0.000

.000

12-2018

.000

0.000

.000

12-2019

.000

0.000

.000

12-2020

.000

0.000

.000

12-2021

.000

0.000

.000

12-2022

.000

0.000

.000

12-2023

.000

0.000

.000

12-2024

.000

0.000

.000

12-2025

.000

0.000

.000

12-2026

.000

0.000

.000

12-2027

.000

0.000

.000

12-2028

.000

0.000

.000

12-2029

.000

0.000

.000

12-2030

.000

0.000

.000

12-2031

.000

0.000

.000

S Tot

.000

0.000

.000

After

.000

0.000

.000

Total

.000

0.000

.000

(22)

(23)

(24)

(25)

(26)

(27)

(29)

(30)

(31)

(21)

Operating

Wells

Workover

3rd Party

Other

(28)

Future Net

Cumulative

Cum.Cash Flow

End

Expense

Gross

Net

Expense

COPAS

Deductions

Investment

Cash Flow

Disc.@ 10. %

Mo-Year

Count

12-2013

5.400

0.0

0.000

.000

-5.400

-5.141

12-2014

5.400

0.0

0.000

.000

-5.400

-10.800

-9.794

12-2015

4.603

0.0

0.000

.000

-4.603

-15.403

-13.407

12-2016

2.400

0.0

0.000

.000

-2.400

-17.803

-15.101

12-2017

2.400

0.0

0.000

.000

-2.400

-20.203

-16.635

12-2018

2.400

0.0

0.000

.000

-2.400

-22.603

-18.024

12-2019

2.400

0.0

0.000

.000

-2.400

-25.003

-19.281

12-2020

2.400

0.0

0.000

.000

-2.400

-27.403

-20.419

12-2021

2.400

0.0

0.000

.000

-2.400

-29.803

-21.449

12-2022

2.400

0.0

0.000

.000

-2.400

-32.203

-22.382

12-2023

2.400

0.0

0.000

.000

-2.400

-34.603

-23.226

12-2024

2.400

0.0

0.000

.000

-2.400

-37.003

-23.990

12-2025

2.400

0.0

0.000

.000

-2.400

-39.403

-24.681

12-2026

2.400

0.0

0.000

.000

-2.400

-41.803

-25.307

12-2027

2.400

0.0

0.000

.000

-2.400

-44.203

-25.874

12-2028

2.400

0.0

0.000

.000

-2.400

-46.603

-26.387

12-2029

2.400

0.0

0.000

.000

-2.400

-49.003

-26.851

12-2030

2.400

0.0

0.000

.000

-2.400

-51.403

-27.272

12-2031

2.400

0.0

0.000

.000

-2.400

-53.803

-27.652

S Tot

53.803

0.000

.000

-53.803

-27.652

After

44.816

0.000

.000

-44.816

-98.619

-30.720

Total

98.619

0.000

.000

-98.619

-30.720

SEC Pricing (12-31-2012)

Percent

Cum. Disc.

WTI Cushing

Henry Hub

.00

-98.619

Year

Oil $/STB

Gas $/MMBTU

5.00

-48.431

2011

94.71

2.76

9.00

-33.133

Thereafter

FLAT

10.00

-30.720

Cap

94.71

2.76

12.00

-26.880

15.00

-22.784

Expenses and investments provided by Eagle Rock Energy

12 Months in first year 37.741 Year Life (09/2050)

THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.

TEXAS REGISTERED ENGINEERING FIRM F-693.

Cawley, Gillespie & Associates, Inc.

Table I - PUD

Composite Reserve Estimates and Economic Forecasts
Eagle Rock Energy Partners, L.P. Interests
Certain Properties in Various States
Proved Undeveloped Reserves
As of December 31, 2012

(1)
End

(2)
Gross Oil
Production

(3)
Gross Gas
Production

(4)
Gross NGL
Production

(5)
Net Oil
Production

(6)

Net Gas
Sales

(7)
Net NGL
Production

(8)
Avg Oil
Price

(9)
Avg Gas
Price

(10)
Avg NGL
Price

Mo-Year

MBBLS

MMCF

MBBLS

MMCF

MBBLS

$/BBL

$/MCF

$/BBL

12-2013

246.7

4,703.7

217.6

113.087

430.422

42.356

-1.405

93.305

1.068

2.947

0.470

44.517

12-2014

600.5

27,706.3

917.5

173.531

3,891.080

138.406

-2.091

92.619

1.010

2.788

0.419

39.674

12-2015

660.5

38,931.4

1,278.2

154.164

5,155.824

172.294

-2.227

92.483

1.009

2.785

0.411

38.966

12-2016

581.8

32,297.6

1,106.0

157.377

4,400.613

170.688

-2.630

92.080

1.017

2.806

0.415

39.293

12-2017

420.0

27,465.2

1,004.4

128.854

3,762.875

170.069

-2.662

92.048

1.013

2.795

0.418

39.615

12-2018

384.8

24,759.1

933.6

144.108

3,381.740

161.635

-2.828

91.882

1.012

2.793

0.421

39.872

12-2019

302.5

20,016.3

738.3

110.411

2,809.988

131.128

-2.862

91.848

1.011

2.791

0.424

40.141

12-2020

255.8

17,342.4

632.4

92.830

2,452.801

112.108

-2.866

91.844

1.011

2.790

0.424

40.176

12-2021

222.5

15,384.7

556.8

80.472

2,186.248

98.343

-2.865

91.845

1.011

2.790

0.424

40.172

12-2022

198.4

13,941.0

501.6

69.750

1,980.774

87.365

-2.881

91.829

1.011

2.789

0.424

40.150

12-2023

179.8

12,797.9

458.4

61.870

1,819.216

78.943

-2.892

91.818

1.010

2.788

0.424

40.111

12-2024

164.8

11,893.5

424.4

56.623

1,694.652

72.763

-2.889

91.821

1.010

2.787

0.423

40.058

12-2025

151.8

11,070.6

393.9

51.965

1,581.623

67.237

-2.888

91.822

1.010

2.787

0.422

39.998

12-2026

140.4

10,213.2

369.1

48.142

1,485.633

62.704

-2.886

91.824

1.009

2.786

0.422

39.934

12-2027

130.8

9,508.2

347.4

44.845

1,400.410

58.777

-2.885

91.825

1.009

2.786

0.421

39.867

12-2028

123.2

8,992.9

329.0

42.061

1,326.315

55.435

-2.885

91.825

1.009

2.785

0.420

39.801

12-2029

115.7

8,433.5

310.4

39.351

1,247.700

52.124

-2.886

91.824

1.009

2.786

0.420

39.737

12-2030

105.0

7,868.2

290.8

34.405

1,170.484

47.195

-2.980

91.730

1.008

2.782

0.410

38.791

12-2031

99.4

7,449.5

275.8

32.514

1,108.680

44.701

91.732

2.782

38.778

S Tot

5,084.3

310,775.3

11,085.6

1,636.359

43,287.076

1,824.271

92.120

2.792

39.832

After

1,168.8

101,734.4

3,939.1

354.023

14,596.615

597.089

91.596

2.785

38.357

Total

6,253.0

412,509.6

15,024.7

1,990.383

57,883.691

2,421.360

92.027

2.790

39.468

Cum

1,371.9

26,273.5

Ult

7,624.9

438,783.2

15,024.7

(12)

(13)

(14)

(15)

(16)

(17)

(18)

(19)

(11)

Oil

Gas

NGL

Exxon

Sulfur

Total

Production

Ad Valorem

(20)

End

Revenue

Retained

Revenue

Taxes

$/BOE6

Mo-Year

12-2013

10,551.546

1,268.449

1,885.562

-326.412

388.474

13,767.619

627.778

.000

1.140

12-2014

16,072.338

10,846.510

5,491.092

-335.503

401.461

32,475.899

1,376.504

8.174

2.575

12-2015

14,257.515

14,359.918

6,713.686

-300.198

361.341

35,392.262

1,627.463

39.461

2.815

12-2016

14,491.332

12,346.487

6,706.818

-269.291

326.076

33,601.423

1,676.652

58.461

3.039

12-2017

11,860.686

10,515.536

6,737.305

-240.237

292.644

29,165.934

1,478.370

68.468

3.317

12-2018

13,240.936

9,443.873

6,444.712

-214.931

263.399

29,177.990

1,528.148

115.987

3.518

12-2019

10,141.054

7,842.603

5,263.594

-192.283

237.076

23,292.045

1,204.599

95.759

3.903

12-2020

8,525.911

6,844.118

4,504.011

0.000

213.938

20,087.978

1,040.970

81.208

4.232

12-2021

7,390.956

6,098.905

3,950.693

0.000

192.004

17,632.558

910.459

70.606

4.543

12-2022

6,405.057

5,524.012

3,507.718

0.000

172.816

15,609.603

799.523

62.794

4.854

12-2023

5,680.756

5,072.012

3,166.435

0.000

155.546

14,074.748

716.548

56.640

5.145

12-2024

5,199.177

4,723.628

2,914.736

0.000

140.365

12,977.906

659.237

51.777

5.398

12-2025

4,771.564

4,407.284

2,689.348

0.000

125.974

11,994.170

607.748

47.476

5.662

12-2026

4,420.593

4,138.995

2,504.028

0.000

113.385

11,177.001

564.975

43.961

5.916

12-2027

4,117.844

3,900.873

2,343.259

0.000

102.053

10,464.029

527.659

40.940

6.169

12-2028

3,862.245

3,693.990

2,206.355

0.000

92.093

9,854.682

495.784

38.405

6.412

12-2029

3,613.412

3,475.661

2,071.255

0.000

82.651

9,242.979

464.071

35.962

6.686

12-2030

3,155.962

3,256.435

1,830.718

0.000

8,243.115

399.443

33.878

6.963

12-2031

2,982.555

3,084.227

1,733.403

0.000

7,800.185

377.725

31.995

7.239

S Tot

150,741.440

120,843.516

72,664.727

-1,878.855

3,661.297

346,032.125

17,083.654

981.953

4.153

After

32,427.160

40,655.058

22,902.553

0.000

95,984.770

4,473.886

353.286

10.327

Total

183,168.600

161,498.573

95,567.280

-1,878.855

3,661.297

442,016.895

21,557.540

1,335.239

5.637

(22)

(23)

(24)

(25)

(26)

(27)

(29)

(30)

(31)

(21)

Operating

Wells

Workover

3rd Party

Other

(28)

Future Net

Cumulative

Cum.Cash Flow

End

Expense

Gross

Net

Expense

COPAS

Deductions

Investment

Cash Flow

Disc.@ 10. %

Mo-Year

Count

12-2013

105.382

6.4

0.000

136.774

39,872.786

-26,975.102

-26,405.720

12-2014

449.251

24.6

0.000

1,899.147

59,856.450

-31,113.627

-58,088.729

-54,077.136

12-2015

715.889

101

33.9

0.000

2,451.983

42,486.988

-11,929.522

-70,018.251

-63,875.913

12-2016

932.135

114

39.7

0.000

2,112.491

17,582.123

11,239.561

-58,778.690

-56,183.766

12-2017

1,105.043

132

48.9

0.000

1,769.054

23,372.252

1,372.748

-57,405.943

-55,147.534

12-2018

1,315.821

132

48.9

0.000

1,543.273

.000

24,674.762

-32,731.181

-40,836.582

12-2019

1,314.297

131

48.9

0.000

1,277.434

.000

19,399.956

-13,331.225

-30,660.378

12-2020

1,314.297

131

48.9

0.000

1,116.724

.000

16,534.780

3,203.555

-22,812.505

12-2021

1,314.297

131

48.9

0.000

996.792

.000

14,340.403

17,543.958

-16,652.994

12-2022

1,309.538

131

48.9

0.000

907.138

.000

12,530.610

30,074.568

-11,779.760

12-2023

1,306.322

131

48.9

0.000

835.861

.000

11,159.377

41,233.945

-7,852.583

12-2024

1,306.322

131

48.9

0.000

779.416

.000

10,181.154

51,415.098

-4,609.711

12-2025

1,306.322

131

48.9

0.000

727.912

.000

9,304.710

60,719.808

-1,927.290

12-2026

1,305.984

131

48.9

0.000

684.667

.000

8,577.414

69,297.223

311.138

12-2027

1,305.776

127

48.9

0.000

646.280

.000

7,943.374

77,240.597

2,187.671

12-2028

1,305.283

127

48.9

0.000

612.920

.000

7,402.291

84,642.887

3,770.501

12-2029

1,301.672

126

48.8

0.000

578.335

.000

6,862.939

91,505.826

5,098.782

12-2030

1,269.006

124

48.0

0.000

542.441

.000

5,998.346

97,504.172

6,149.713

12-2031

1,269.006

124

48.0

0.000

514.199

.000

5,607.259

103,111.432

7,039.059

S Tot

21,551.646

0.000

20,132.842

183,170.599

103,111.432

7,039.059

After

25,594.545

0.000

7,191.241

.000

58,371.812

161,483.244

11,597.642

Total

47,146.191

0.000

27,324.082

183,170.599

161,483.244

11,597.642

SEC Pricing (12-31-2012)

Percent

Cum. Disc.

WTI Cushing

Henry Hub

.00

161,483.244

Year

Oil $/STB

Gas $/MMBTU

5.00

57,407.192

2011

94.71

2.76

9.00

18,353.771

Thereafter

FLAT

10.00

11,597.642

Cap

94.71

2.76

12.00

468.291

15.00

-11,822.580

Expenses and investments provided by Eagle Rock Energy

12 Months in first year 49.999 Year Life (12/2062)

THESE DATA ARE PART OF A CG&A REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT.

TEXAS REGISTERED ENGINEERING FIRM F-693.

Cawley, Gillespie & Associates, Inc.

Eagle Rock Energy Partners L P (EROC) Inactive CORRESPCorrespondence with SEC