Erin Energy (ERINQ) CORRESP Correspondence with SEC

Houston Headquarters

1330 Post Oak Blvd, Suite 2250, Houston, TX 77056

Tel: 713-797-2940 Fax: 713-797-2990

April 4, 2013

VIA EDGAR CORRESPONDENCE

Mr. Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

101 F Street N.E.

Washington, D.C. 20549

Re:         CAMAC Energy, Inc.

Form 10-K for Fiscal Year Ended December 31, 2011

Filed March 15, 2012

Definitive Proxy Statement on Schedule 14A

Filed April 30, 2012

Dear Mr. Skinner:

We have received your letter dated April 3, 2013 (the “Comment Letter”), addressed to Dr. Kase Lukman Lawal, Chief Executive Officer of CAMAC Energy, Inc. (the “Company”), pursuant to which you provided comments from the staff (the “Staff”) of the United States Securities and Exchange Commission (“SEC”) pertaining to our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (File No. 1-34525) filed with the SEC on March 15, 2012 (“Form 10-K”) and our Definitive Proxy Statement on Schedule 14A (File No. 1-34525) filed with the SEC on April 30, 2012 (the “Proxy Statement”).

We have set forth below the responses of the Company to the Staff’s comments dated April 3, 2013.  For your convenience, the comments contained in your Comment Letter are set forth below verbatim in italicized text.

Form 10-K for Fiscal Year Ended December 31, 2011

Financial Statements

Note 3:  Significant Accounting Policies, page 66

Impairment of Long-Lived Assets, page 67

1. Please describe for us the methodology, data and analysis used to determine the year end 2012 and 2011 estimated quantities of proved, probable and possible reserves and the risk factors of 81% and 53% and 45% and 28%, respectively, related to probable and possible reserves for each year end.

Response:

The methodologies used to determine the proved, probable and possible reserves for year-end 2011 and 2012 were different.  For 2011, the previous independent reserves evaluator had used a combination of methodologies, consisting of DCA type curve, application of reservoir simulation and volumetric approach (recovery factors) (see Exhibit A). However in 2012, the new independent reserves evaluator used only DCA type curve approach for the reserves evaluation. A set of type curves were generated from an existing producing well to create 1P, 2P and 3P profiles (see Exhibit B). These type curves were applied to both an existing and planned wells.

1

The T1A reservoir has both the Central (east and west fault blocks) and the West culminations. Oyo-5 is producing from the western fault block of the central culmination while the only other producing well, Oyo-6 is completed on the western culmination. Both wells are producing from T1A reservoir. In the Central culmination, a minor fault separates the reservoir into east and west fault block (see Exhibit C).

In the T1B reservoir, six meters of oil were penetrated in Oyo-1 well, but PVT data indicate the reservoir to be under-saturated.

Year-end 2011 and 2012 risk factors varied as a result of the change in reserve evaluation methodology. The approach taken in assessing the risk factors was to identify the type of risks associated with each evaluation method.  In doing this, a team of geoscientists and engineers were assembled in risking sessions to estimate the appropriate risks factors for both 2011 and 2012 reserves estimates.

Year end 2012 risk factors of 81% for Probable reserves and 53% for Possible reserves were derived using two risk elements: risk associated with the in-place volume calculation and risk associated with achieving the expected production well performance.  The in-place volume risk relates to uncertainty in rock and fluid parameters while the well performance risk relates principally to the ability of future wells to achieve the expected production performance.  In the Possible category, as there are no penetrations east of the fault, the in-place volume risk is deemed to be much higher.

Details of these risk factors as estimated are presented in Exhibit D.

For year-end 2011, due to the different methodology used by the reserves estimator, five risk elements were considered for Probable and Possible reserves. These are, risk associated with expected well performance, risk associated with in-place volume calculation, risk associated with reservoir simulation results, risk associated with finding estimated T1B volumes, and risk associated with the recovery factors applied in the 3P case.

Three risk elements were used for the Probable (P2) category: well performance risk, reservoir simulation results risk, finding estimated T1B volumes risk. The following three risk elements were used for the Possible (P3) category: finding estimated T1B volumes risk, in-place volume calculation, and recovery factor risk.

The calculation and resulting composite risk factors are presented in Exhibit E.

  2. Please provide us a reasonably detailed summary of the cash flow recoverability analyses related to the year ended 2012.  The summary should clearly indicate how estimated revenues have been determined and how variable and fixed costs have been taken into consideration.

Response:

The cash flow recoverability analysis for 2012 was derived from the Oyo Field economic model used by Gaffney Cline & Associates (“GCA”) to calculate its estimate of the Company’s Net Cash Flows from 3P (Proved + Probable + Possible) Reserves as of December 31, 2012 (see Exhibit F).  The Company applied internally generated risk factors to the gross reserve volumes estimated by GCA as follows:  100% to Gross Proved Reserves (1P), 81% to Gross Probable Reserves (P2), and 53% to Gross Possible Reserves (P3) (see Exhibit G).  These risk factors reflect the Company’s internal technical analysis of the recoverability risk associated with each category of reserve volumes.  The details of this risking analysis are explained in our response to the Staff’s comment 1 above.

The Risked Gross 3P Reserve volumes are then flowed through GCA’s Oyo Field economic model to calculate the Risked 3P Reserve volumes net to the Company (see Exhibit H).  The Risked 3P Reserve volumes net to the Company are used to calculate expected net cash flows using the same price, tax, net capital investment, and net operating expense assumptions as used in GCA’s calculation.  The net capital investment and net operating expenses are not assumed to be a variable of reserve volumes due to the fixed nature of offshore oil and gas operating costs.  The Company excluded resulting negative net cash flows from fiscal years 2023 and 2024 from its total net cash flows, under the assumption that it would discontinue operations rather than produce in those years.  Negative net cash flows from fiscal year 2022 are included however, since those net cash flows include the Company’s share of abandonment costs which are assumed to be paid in the final year of producing operations.

3. Please tell us why the risk factors in your 2012 recoverability analysis have been revised upward, as compared to those used for 2011, representing greater certainty of attaining the estimated volumes.

Response:

The risk factors in the 2012 recoverability analysis have been revised upward to reflect the difference in the reserve evaluation methodology that was used in 2012 compared to 2011.

The 2012 approach does represent a higher degree of certainty, and is supported by the 2013 production performance - since the beginning of 2013, the actual monthly production performance have exceeded the 2P type curve predicted production (see Exhibit I).

2

4. Please tell us why the risk factors of 45% for probable and 28% for possible are more appropriate than the 50% and 10% factors used in your prior recoverability analysis for 2011.

Response:

The 45% for probable and 28% for possible are consistent with the more rigorous approach we adopted in 2012.

5. We note you state the independent reserves evaluator based the type curves for all the planned future wells on the decline curve from an existing well.  Furthermore, you state that you believe the existing well on which the type curves were based is not representative of future wells because the well was damaged from the start due to operational issues.

● Please clarify if the subject decline type curve was the basis of the reserve estimates as of December 31, 2011 or December 31, 2012.

Response:

The decline type curve shown in Exhibit B was the basis of the reserves estimates for December 31, 2012 for both existing and planned new wells for all categories of reserves.  The independent reserves evaluator used the actual performance from Oyo-5 to generate 1P, 2P and 3P type curves.  A similar approach was used to generate type curves for Oyo-6.  For December 31, 2011, a combination of methodologies, consisting of decline curve, simulation and volumetric approach was used.  The methodology for each well used for 2011 and 2012 are set forth in Exhibit A.

● Please provide the technical data and analysis that supports that the subject well was damaged.

Response:

Well-5, on which the type curves were based, is completed horizontally and produces in the middle of a 40 meter oil column in a saturated reservoir.  The initial solution GOR based on PVT analysis is 650 scf/bbl.  This well started producing at about solution GOR and within a few days the producing GOR rapidly increased and far exceeded 10,000 scf/bbl.  The high GOR is believed to be a result of poor cement bond at the 9 5/8” casing shoe, excessive initial production rate and aggressive bean up during well clean-up/production which resulted in gas cusping.  The two charts in Exhibit J show the increasing GOR from start of production (12/05/09) and the choke trends for Oyo-5.

● Please tell us why the subject well’s performance will not be representative of future wells and why.

Response:

In the planning for the future wells, actions will be taken to ensure that early breakthrough is prevented.  Such measures include rotation of the casing prior to cementing, use of gas-block cement slurry and more gentle bean up, all of which were absent in Oyo-5. In addition, while Oyo-5 was produced at maximum rate in excess of 13,000 bopd, the new wells are planned to be produced at maximum 7,000 bopd.  Well clean-up will also be based on less aggressive choke operation.

In Connection with its response, CAMAC Energy Inc. acknowledges that:

● CAMAC Energy Inc. is responsible for the adequacy and accuracy of the disclosures in the filings;

● Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filings; and

● CAMAC Energy Inc. 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.

If you have any questions or comments regarding this letter, please contact the undersigned at 713 797 2940.

Very truly yours
CAMAC Energy Inc.
By:	/s/ Earl W. McNiel
	Earl W. McNiel
	Senior Vice President & Chief Financial Officer

3

Exhibit A

Year	Reserves Category	Reservoirs	Fault Block	Wells	Methodology	Remarks
2011	PDP	T1A Central	West	Oyo-5H	DCA	Based on Oyo-5 DCA
		T1A West		Oyo-6H	DCA	Based on Oyo-6 DCA
	PUD	T1A Central	West	Oyo7V, 8V & 9H	Simulation	History matched for well-5 and generated production rates for the PUD wells
	Probable	T1A Central	West	Oyo-5H, 7V, 8 V& 9H	Simulation	History matched for well-5 and made more slightly optimistic assumption for well initial rate
		T1B Central		Oyo-7V & Oyo8V	Estimation	Using new wells in L1A central as analogue
		T1A West		Oyo-6H	DCA	Based on Oyo-6 DCA
	Possible	T1A Central	West	Oyo-5H, 7V, 8 V& 9H	Volumetric	Assumed 35% recovery for L1A Central and T1B reservoirs and 26% for the L1A west reservoir
		T1A Central	East	Oyo-10H, 11H & 12H
		T1B Central		Oyo-7V & Oyo8V
		T1A West		Oyo-6H
2012	PDP	T1A Central	West	Oyo-5H	DCA	Based on Oyo-5 DCA
		T1A West		Oyo-6H	DCA	Based on Oyo-6 DCA
	PUD	T1A Central	West	Oyo7H, 8H & 9H	DCA	Used well-5 1P DCA type curve
	Probable	T1A Central	West	Oyo 5H,7H, 8H & 9H	DCA	Used well-5 2P DCA type curve
		T1A West		Oyo-6H	DCA	Based on Oyo-6 DCA
	Possible	T1A Central	West	Oyo 5H,7H, 8H & 9H	DCA	Used well-5 3P DCA type curve
		T1A Central	East	Oyo-10H, 11H & 12H	DCA	Used well-5 3P DCA type curve
		T1A West		Oyo-6H	DCA	Based on Oyo-6 DCA

****** H – horizontal well and V- Vertical Well

4

Exhibit B

5

Exhibit C

6

Exhibit D

YE 2012 P2 and P3 Risk Factors

	P2		P3
	(probable)		(possible)
	3.5 mmbo*		16.8 mmbo*
Risk elements	Risk Factors				Comments
1. In -place volume		0.95		0.72	P2 (0.95): risk factor accounts for uncertainty in rock and fluid input parameters
					P3 (0.72): volumes lie east of the fault where no wells have been drilled;
					- principal risk is geologic
					- geologic risking: seal = 1, trap = 1, charge = 0.9, reservoir quality          & presence = 0.8
					- carries higher in-place volume risk
2.  Expected Well performance		0.85		0.74	P2 (0.85) rationale/considerations:
						1. Oyo -5 type well was sub-optimally completed and produced,
						hence performance of future wells should be better
						2. Risked volume is small (3.5 mmbo)
					P3 (0.74) rationale: uncertainty in reservoir quality across the fault, hence performance
Composite Risk Factor		0.81		0.53	Assumes equal weighting of both risk elements

Only TIA included in YE 2012 assessment (both TIA and TIB were included in 2011). 

7

Exhibit E

YE 2011 P2 and P3 Risk Factors

Volume Split/well

	(Probable)	(Possible)
Well 5	0.2	n/a
Well 6	0.2	n/a
Well 7	7.9	n/a
Well 8	7.9	n/a
Well 9	3.4	n/a
TOTAL	19.7 mmbo	41.4 mmbo

Risk Factor Elements

	P2	P3
	(Probable)	(Possible)	Comments
1. DCA	0.85	n/a	P2 DCA as in 2012
2. Confidence in simulation	0.7	n/a
2. Confidence in T1B volumes	0.2	0.2	Uncertainty in GRV relating to mapping uncertainty
3. STOOIP Volume	n/a	0.72	STOOIP risking: seal = 1, trap = 1, charge = 0.9, reservoir quality & presence = 0.8
4. Recovey Factor	n/a	0.45	Low probability that the simulated EUR/well (10 mmbo) will be achieved
			when compared with the Oyo-7 4.5 mmbo EUR expectation

P2 Composite Risk Factor calculation

	Unrisked Volume				Risked volume
	(mmbo)		Risk		(mmbo)
T1A  wells 5,6		0.4		0.85		0.34
T1A  wells 7,8,9		9.2		0.7		6.44
T1B  wells 7 & 8		10		0.2		2
Total risked volume						8.78
Total unrisked volume						19.7
Composite Risk Factor (total risked volume/total unrisked volume)						0.45

P3 Composite Risk Factor calculation

	Unrisked Volume				Risked volume
	(mmbo)		Risk		(mmbo)
T1A  wells 10,11,12		29		0.45		13.05
T1A  wells 5,6,7,8,9		2.4		0.45		1.08
T1B  wells 7 & 8		10		0.2		2
Total risked volume						16.13
Total unrisked volume						41.4
Recovery risk factor (total risked volume/total unrisked volume)						0.39
STOOIP risk factor						0.72
Composite Risk Factor						0.28

8

Exhibit F

  SUMMARY PROJECTION OF RESERVES AND REVENUE CAMAC ENERGY INC. INTEREST OYO FIELD, OIL MINING LEASE 120, OFFSHORE NIGERIA AS OF DECEMBER 31, 2012   PROVED (1P)  RESERVES

									Net		Net
	Oil Reserves				Gross				Capital		Operating		Net		Cumulative PWAT
Period	Gross		Net		Revenue		Taxes		Investment		Expense		Cash Flow			10.0%
Ending	(MBBL)		(MBBL)		$(M)		$(M)		$(M)		$(M)		$(M)		$(M)
12/31/2013		1,544.2		111.1		12,531.8		267.7		0.0		0.0		12,264.1		11,693.3
12/31/2014		3,497.9		771.4		86,985.2		4,044.6		58,500.0		26,557.7		- 2,117.1		9,858.2
12/31/2015		3,841.2		585.8		66,060.4		7,906.1		0.0		26,737.4		31,416.9		34,614.3
12/31/2016		2,224.0		418.8		47,226.2		3,718.9		0.0		25,890.8		17,616.4		47,233.8
12/31/2017		1,624.4		359.7		40,559.6		2,114.8		300.0		25,577.0		12,567.9		55,418.4
12/31/2018		1,286.6		322.6		36,379.9		1,234.8		0.0		25,400.1		9,744.9		61,187.6
12/31/2019		1,045.4		290.6		32,766.5		568.5		0.0		25,273.9		6,924.2		64,914.2
12/31/2020		856.0		238.0		26,835.5		30.6		0.0		25,174.7		1,630.1		65,711.8
12/31/2021
12/31/2022
12/31/2023
12/31/2024
Total		15,919.7		3,097.9		349,345.0		19,886.0		58,800.0		180,611.7		90,047.3		65,711.8

PROBABLE UNDEVELOPED RESERVES (P2)

					Future				Net		Net		Future		Cumulative
	Oil Reserves				Gross				Capital		Operating		Net		PW at
Period	Gross		Net		Revenue		Taxes		Costs		Expense		Revenue			10.0%
Ending	(MBBL)		(MBBL)		$(M)		$(M)		$(M)		$(M)		$(M)		$(M)
12/31/2013		166.3		15.2		1,709.6		411.5		0.0		0.0		1,298.1		1,237.7
12/31/2014		605.2		61.4		6,924.3		1,589.2		0.0		- 56.7		5,391.7		5,911.1
12/31/2015		700.5		68.1		7,674.8		1,885.2		0.0		- 46.7		5,836.2		10,510.0
12/31/2016		393.4		40.0		4,513.1		1,082.9		0.0		- 32.3		3,462.5		12,990.4
12/31/2017		284.7		29.4		3,319.4		799.2		0.0		- 24.8		2,545.0		14,647.8
12/31/2018		224.6		202.9		22,879.5		641.7		0.0		- 20.0		22,257.8		27,824.9
12/31/2019		181.7		58.0		6,538.3		527.2		0.0		- 16.6		6,027.6		95,983.2
12/31/2020		148.0		41.9		4,727.6		435.5		0.0		- 13.9		4,306.0		33,175.8
12/31/2021		120.1		33.5		3,775.8		0.0		0.0		- 11.7		3,787.6		34,860.5
12/31/2022		98.1		27.4		3,092.1		0.0		0.0		291.3		2,800.8		35,993.1
12/31/2023
12/31/2024
Total		2,824.5		550.3		62,062.4		7,372.5		0.0		- 222.6		54,912.5		34,860.5

POSSIBLE UNDEVELOPED RESERVES (P3)

					Future				Net		Net		Future		Cumulative
	Oil Reserves				Gross				Capital		Operating		Net		PW at
Period	Gross		Net		Revenue		Taxes		Costs		Expense		Revenue			10.0%
Ending	(MBBL)		(MBBL)		$(M)		$(M)		$(M)		$(M)		$(M)		$(M)
12/31/2013		86.4		8.0		904.2		223.9		0.0		0.0		680.3		648.6
12/31/2014		308.7		27.9		3,142.1		836.8		0.0		- 350.6		2,655.9		2,950.7
12/31/2015		357.2		171.5		19,343.4		- 246.4		27,900.0		- 383.1		- 7,927.1		- 3,295.8
12/31/2016		2,025.4		373.6		42,129.6		4,340.3		27,900.0		366.5		9,522.9		3,525.9
12/31/2017		2,783.3		489.1		55,154.8		6,590.1		27,600.0		688.8		20,275.9		16,730.2
12/31/2018		3,288.8		1,186.9		133,847.9		9,593.1		0.0		895.6		123,359.2		89,761.9
12/31/2019		1,847.7		625.3		70,511.2		5,463.9		0.0		461.6		64,585.7		124,522.3
12/31/2020		1,338.4		453.6		82,710.3		4,463.8		0.0		25,482.6		52,764.0		246,321.7
12/31/2021		1,043.7		345.6		64,740.8		3,074.2		0.0		25,328.0		36,338.7		262,485.1
12/31/2022		834.4		265.8		51,201.5		6,810.8		0.0		25,213.2		19,177.4		270,239.7
12/31/2023		1,223.8		362.0		40,821.0		7,842.2		0.0		25,121.6		7,857.2		278,096.9
12/31/2024		997.9		289.0		32,591.4		3,258.5		0.0		25,048.7		4,284.3		282,381.2
Total		13,914.0		3,947.2		523,685.9		41,150.5		83,400.0		77,702.5		321,432.8		183,188.9

PRELIMINARY ESTIMATES BASED ON SEC PRICE AND COST PARAMETERS

9

Exhibit G

KBbls

	2013		2014		2015		2016		2017		2018		2019		2020		2021			2022			2023			2024			Total
PDP		752.1		548.0		428.2		350.5		294.1		253.0		220.6		194.5		171.8			153.2			137.4			124.3
PUD		792.1		2,949.9		3,413.0		1,873.5		1,330.3		1,033.6		824.8		661.5		527.7			422.2			337.8			271.0
Proved (1P)		1,544.2		3,497.9		3,841.2		2,224.0		1,624.4		1,286.6		1,045.4		856.0		699.5	(a)		575.4	(a)		475.2	(a)		395.2	(a)		18,065.1
Probable Undeveloped (P2)		166.3		605.2		700.5		393.4		284.7		224.6		181.7		148.0		120.1			98.1			80.4	(a)		66.3	(a)
Proved + Probable (2P)		1,710.4		4,103.1		4,541.7		2,617.4		1,909.1		1,511.3		1,227.1		1,004.0		819.6			673.5			555.6			461.5			21,134.3
Possible Undeveloped (P3)		86.4		308.7		357.2		2,025.4		2,783.3		3,288.8		1,847.7		1,338.4		1,043.7			834.4			668.2			536.4
Proved + Probable + Possible (3P)		1,796.8		4,411.8		4,898.9		4,642.8		4,692.4		4,800.0		3,074.8		2,342.5		1,863.3			1,507.9			1,223.8			997.9			36,252.9

	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023	2024	Total
P2	166.3	605.2	700.5	393.4	284.7	224.6	181.7	148.0	120.1	98.1	80.4	66.3		3,069.2
P3	86.4	308.7	357.2	2,025.4	2,783.3	3,288.8	1,847.7	1,338.4	1,043.7	834.4	668.2	536.4		15,118.6

	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023	2024	Total
Risked P2 (81%)	134.3	488.7	565.6	317.7	229.9	181.4	146.7	119.5	97.0	79.2	64.9	53.5		2,478.4
Risked P3 (53%)	45.4	162.2	187.7	1,064.2	1,462.4	1,727.9	970.8	703.2	548.4	438.4	351.1	281.8		7,943.3

	2013		2014		2015		2016		2017		2018		2019		2020		2021		2022		2023		2024		Total
Risked 1P	1,544.2		3,497.9		3,841.2		2,224.0		1,624.4		1,286.6		1,045.4		856.0		699.5		575.4		475.2		395.2			18,065.1
Delta to 1P	0		0		0		0		0		0		0		0		0		0		0		0			0
Risked 2P	1,678.4		3,986.6		4,406.8		2,541.6		1,854.3		1,468.0		1,192.1		975.5		796.5		654.6		540.1		448.7			20,543.5
Delta to 2P	(32	)	(116	)	(135	)	(76	)	(55	)	(43	)	(35	)	(28	)	(23	)	(19	)	(15	)	(13	)		(591	)
Risked 3P	1,723.8		4,148.8		4,594.5		3,605.8		3,316.7		3,195.9		2,162.9		1,678.7		1,344.9		1,093.0		891.2		730.6			28,486.8
Delta to 3P	(73	)	(263	)	(304	)	(1,037	)	(1,376	)	(1,604	)	(912	)	(664	)	(518	)	(415	)	(333	)	(267	)		(7,766	)

(a) Volumes excluded from GCA standalone 1P and P2 cases as expected net cash flows are negative beginning in 2021 and 2023, in the respective cases

10

Exhibit H

AS OF DECEMBER 31, 2012

PROPERTIES LOCATED IN OYO FIELD, NIGERIA

CAMAC HOLDINGS, INC. INTEREST

PROVED + PROBABLE + POSSIBLE (3P) RESERVES

											Net		Net
	Oil Reserves				Average		Gross				Capital		Operating		Net		Cumulative PWAT
Period	Gross		Net		Oil Price		Revenue		Taxes		Investment		Expense		Cash Flow			10.0%
Ending	(MBBL)		(MBBL)		($/BBL)			(M$)		(M$)		(M$)		(M$)		(M$)		(M$)
12/31/2013		1,724		128		113		14,382		714		0		0		13,668		13,032
12/31/2014		4,149		837		113		94,359		5,759		58,500		26,431		3,669		16,212
12/31/2015		4,595		794		113		89,559		8,693		27,900		26,614		26,353		36,977
12/31/2016		3,606		707		113		79,753		6,234		27,900		26,208		19,412		50,883
12/31/2017		3,317		693		113		78,199		5,552		27,900		26,089		18,658		63,034
12/31/2018		3,196		1,244		113		140,285		6,797		0		26,039		107,449		126,646
12/31/2019		2,163		666		113		75,159		3,864		0		25,615		45,680		151,231
12/31/2020		1,679		507		113		57,177		2,477		0		25,416		29,284		165,559
12/31/2021		1,345		395		113		44,574		1,505		0		25,279		17,790		173,472
12/31/2022		1,093		374		113		42,156		765		11,700		25,176		4,516		175,298
12/31/2023		891		258		113		29,081		151		0		25,093		3,838		179,136
12/31/2024		731		208		113		23,420		0		0		25,027		-1,607		177,529
Total 2013-2024		28,487		6,811				768,106		42,512		153,900		282,985		288,709		177,529
Total 2013-2022		26,865		6,346				715,604		42,361		153,900		232,865		286,478		175,298

11

Exhibit I

	Predicted Average Field 1P Oil Rate (b/d)	Predicted Average Field 2P Oil Rate (b/d)	Predicted Average Field 3P Oil Rate (b/d)		Actual Field Oil Rate (b/d)
1/1/2013	2437	2442	2447			2432
2/1/2013	2356	2365	2374			2359
3/1/2013	2281	2293	2304			2360
4/1/2013	2207	2223	2237	To date		2362
5/1/2013	2138	2157	2174
6/1/2013	2073	2094	2114
7/1/2013	2012	2036	2057
8/1/2013	1953	1979	2003
9/1/2013	1898	1926	1952
10/1/2013	1846	1876	1904
11/1/2013	1796	1828	1858
12/1/2013	1749	1783	1814

12

Exhibit J

13