Targa Energy LP - FORM 8-K/A - EX-99.2

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8-K/A - 8-K/A - Targa Energy LP	d612269d8ka.htm
EX-99.1 - EX-99.1 - Targa Energy LP	d612269dex991.htm
EX-23.1 - EX-23.1 - Targa Energy LP	d612269dex231.htm

Exhibit 99.2

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma consolidated financial data reflects Atlas Energy, L.P.’s (NYSE: ATLS; the “Partnership” or “ATLS”) historical results as adjusted on a pro forma basis to give effect to (A) Atlas Resource Partners, L.P.’s (NYSE: ARP; “ARP”) acquisitions of (i) certain assets from Carrizo Oil & Gas, Inc. (NASDAQ: CRZO; “Carrizo”) on April 30, 2012 and the related issuance of 6.0 million common limited partner units in a private placement to partially fund the purchase price, (ii) certain proved reserves and associated assets from Titan Operating, L.L.C. (“Titan”) on July 25, 2012 for 3.8 million ARP common limited partner units and 3.8 million ARP convertible Class B preferred units, as well as $15.4 million in cash for closing adjustments, (iii) DTE Gas Resources, LLC (“DTE”) for gross cash consideration of $257.4 million funded with borrowings under ARP’s revolving and term loan credit facilities, and (iv) certain oil and gas assets from EP Energy E&P Company, L.P. (“EP Energy”) for $705.9 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”), funded with borrowings under ARP’s revolving credit facility, ARP’s issuance of its newly created ARP Class C convertible preferred units to the Partnership and the issuance of the ARP’s 9.25% senior notes due August 15, 2021 (“9.25% ARP Senior Notes”); (B) (i) Atlas Pipeline Partners, L.P.’s (NYSE: APL; “APL”) December 20, 2012 acquisition from Cardinal Midstream, LLC (“Cardinal”) of 100% of the equity interests in three wholly-owned subsidiaries (the “Cardinal Acquisition”), which includes a 60% interest in a joint venture, known as Centrahoma Processing, LLC (“Centrahoma”), of which the remaining 40% interest in Centrahoma is owned by MarkWest Oklahoma Gas Company, LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE; “MWE”), (ii) the related issuance of 10.5 million of APL’s common limited partner units in a public offering to partially fund the purchase, (iii) the related issuance of $175.0 million of APL’s 6.625% senior unsecured notes due on October 1, 2020 (“6.625% APL Senior Notes”) to partially fund the purchase price, and (iv) borrowings from APL’s senior secured revolving credit facility to partially fund the purchase price; and (C) (i) APL’s May 7, 2013 acquisition from TEAK Midstream, LLC (“TEAK”) of 100% of the outstanding member and other ownership interests of TEAK for $1.0 billion, (ii) the related issuance of 11.8 million of APL’s common limited partner units in a public offering to partially fund the purchase price, (iii) APL’s issuance of $400.0 million of its Class D convertible preferred units to partially fund the purchase price, and (iv) the related issuance of $400.0 million of APL’s 4.75% senior unsecured notes due on November 15, 2021 (“4.75% APL Senior Notes”) to partially fund the purchase price. The estimated adjustments to give effect to the acquisitions are described in the notes to the unaudited pro forma financial data.

The unaudited pro forma consolidated statements of operations information for the six months ended June 30, 2013 and the year ended December 31, 2012 assume the following transactions had occurred as of January 1, 2012. In addition, the pro forma consolidated balance sheet as of June 30, 2013 reflects the following transactions as if they had occurred on June 30, 2013:

•

the Carrizo acquisition for gross cash consideration of $190.0 million, net of $3.0 million of purchase price reductions for working capital and other amounts, which was funded through (i) the private placement of approximately 6.0 million ARP common units at a negotiated purchase price of $20.00 per unit and (ii) borrowings of $67.5 million under ARP’s revolving credit facility;

•

the Titan acquisition for 3.8 million ARP common units and 3.8 million ARP convertible Class B preferred units, as well as $15.4 million in cash for closing adjustments, which was funded through borrowings under ARP’s revolving credit facility;

•

the sale of 7.9 million of ARP’s common units for net proceeds of $174.5 million, the net proceeds of which were used to repay borrowings under ARP’s revolving credit facility prior to funding the cash consideration for the DTE acquisition;

•

the DTE acquisition for gross cash consideration of $257.4 million, including $2.4 million of adjustments for working capital, which was funded through borrowings of $179.8 million from ARP’s revolving credit facility and $77.6 from ARP’s term loan credit facility;

•

the issuance of ARP’s 7.75% senior unsecured notes due on January 15, 2021 (“7.75% ARP Senior Notes”) for net proceeds of $268.3 million, which were used to repay all of the indebtedness and accrued interest outstanding under ARP’s term loan credit facility and a portion of that outstanding under ARP’s revolving credit facility;

•

the EP Energy Acquisition for cash consideration of $705.9 million, net of purchase price adjustments, which was funded through borrowings under ARP’s revolving credit facility, the sale of 15.0 million of ARP’s common units for net proceeds of $313.1 million (which were issued in June 2013), the issuance of ARP’s newly created Class C convertible preferred units to ATLS for $86.6 million and net proceeds of $242.8 million from the issuance of 9.25% ARP Senior Notes at a discount of 99.297% (which were issued in July 2013). The historical results of operations for the period January 1, 2012 to December 31, 2012 and from January 1, 2012 to June 30, 2012, which include the results of operations of EP Energy subsequent to its acquisition of the assets on May 24, 2012 and its related party predecessor, were combined for presentation purposes;

•

the Cardinal acquisition for $598.3 million in cash, which was partially funded through (i) the issuance of 10.5 million of APL’s common limited partner units in a public offering, (ii) the issuance of $175.0 million of 6.625% APL Senior Notes, and (iii) borrowings under APL’s revolving credit facility; and

•

the TEAK acquisition for $1.0 billion, which was partially funded through (i) the issuance of 11.8 million of APL’s common limited partner units in a public offering, (ii) the issuance of $400.0 million of APL’s Class D convertible preferred units, and (iii) the issuance of $400.0 million of APL’s 4.75% APL Senior Notes.

The unaudited pro forma consolidated balance sheet and the unaudited pro forma consolidated statements of operations were derived by adjusting the Partnership’s historical consolidated financial statements. However, management of the Partnership believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma financial data presented is for informational purposes only and is based upon available information and assumptions that management of the Partnership believes are reasonable under the circumstances. The allocation of the fair value of the assets acquired and liabilities assumed is based upon their estimated fair values, which are subject to adjustment and could change significantly as the Partnership continues to evaluate the preliminary allocations related to the DTE, EP Energy, Cardinal and TEAK acquisitions. This unaudited pro forma financial information is not necessarily indicative of what the financial position or results of operations of the Partnership would have been had the transactions been consummated on the dates assumed, nor are they necessarily indicative of any future operating results or financial position. The Partnership may have performed differently had the transactions actually occurred on the dates assumed.

Consolidated supplemental oil and gas disclosures as of December 31, 2012, which were presented inclusive of the Carrizo, Titan and DTE acquisitions, were included with the Partnership’s annual filing on Form 10-K for the year ended December 31, 2012 specifically in Item 8: Financial Statements and Supplementary Data – Footnote 21 “Supplemental Oil and Gas Disclosures (Unaudited)”.

In February 2012, the board of directors of the Partnership’s General Partner (“the Board”) approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of the Partnership’s exploration and production assets to ARP on March 5, 2012. The Board also approved the distribution of approximately 5.2 million ARP common units to the Partnership’s unitholders, which were distributed on March 13, 2012 using a ratio of 0.1021 ARP limited partner units for each of the Partnership’s common units owned on the record date of February 28, 2012. The distribution of ARP limited partner units represented approximately 20% of the common limited partner units outstanding at March 13, 2012.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED BALANCE SHEET

June 30, 2013

(in thousands)

(Unaudited)


			Acquisition
	Historical		EP Energy			Adjustments			Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	70,430	$	—		$	705,900	(b)	$	70,430
							(705,900	)(d)
Accounts receivable		250,755		—			—			250,755
Current portion of derivative asset		64,402		—			—			64,402
Subscriptions receivable		11,036		—			—			11,036
Prepaid expenses and other		72,595		—			—			72,595

Total current assets		469,218		—			—			469,218
PROPERTY, PLANT AND EQUIPMENT, NET		4,036,187		722,803	(a,hh)		—			4,758,990
INTANGIBLE ASSETS, NET		570,999		—			—			570,999
INVESTMENT IN JOINT VENTURE		232,090		—			—			232,090
GOODWILL, NET		534,105		—			—			534,105
LONG-TERM DERIVATIVE ASSET		26,759		—			—			26,759
OTHER ASSETS, NET		92,721		—			15,057	(c)		113,278
							5,500	(c)

	$	5,962,079	$	722,803		$	20,557		$	6,705,439

LIABILITIES AND PARTNERS’ CAPITAL/EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	522	$	—		$	—		$	522
Accounts payable		94,270		—			—			94,270
Accrued producer liabilities		140,505		—			—			140,505
Current portion of derivative liability		167		—			—			167
Current portion of derivative payable to Drilling Partnerships		5,969		—			—			5,969
Accrued interest		35,281		—			—			35,281
Accrued well drilling and completion costs		52,425		—			—			52,425
Accrued liabilities		118,006		—			—			118,006

Total current liabilities		447,145		—			—			447,145
LONG-TERM DEBT, LESS CURRENT PORTION		1,944,297		—			371,034	(b)		2,589,739
							248,241	(b)
							26,167	(c)


LONG-TERM DERIVATIVE LIABILITY		130		—			—			130
LONG-TERM DERIVATIVE PAYABLE TO DRILLING PARTNERSHIPS		38		—			—			38
DEFERRED INCOME TAXES, NET		35,513		—			—			35,513
ASSET RETIREMENT OBLIGATIONS AND OTHER		77,890		16,903	(a)		—			94,793
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL/EQUITY:
Common limited partners’ interests		448,808		—			86,625	(b)		533,369
							(2,064	)(c)
Equity		—		705,900	(a)		(705,900	)(d)		—
Accumulated other comprehensive income (loss)		13,927		—			—			13,927

		462,735		705,900			(621,339	)		547,296
Non-controlling interests		2,994,331		—			(3,546	)(c)		2,990,785

Total partners’ capital/equity		3,457,066		705,900			(624,885	)		3,538,081

	$	5,962,079	$	722,803		$	20,557		$	6,705,439

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE SIX MONTHS ENDED JUNE 30, 2013

(in thousands)

(Unaudited)


				For the Period January 1 to May 7, 2013			For the Period January 1 to June 30, 2013
	Historical			TEAK			EP Energy		Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	93,158		$	—		$	77,701	$	—		$	170,859
Well construction and completion		81,329			—			—		—			81,329
Gathering and processing		956,009			34,605			—		—			990,614
Administration and oversight		4,476			—			—		—			4,476
Well services		9,680			—			—		—			9,680
Loss on mark-to-market derivatives		15,024			—			—		—			15,024
Other, net		6,221			(2,729	)		—		119	(e)		3,611

Total revenues		1,165,897			31,876			77,701		119			1,275,593

COSTS AND EXPENSES:
Gas and oil production		34,251			—			35,615		—			69,866
Well construction and completion		70,721			—			—		—			70,721
Gathering and processing		805,609			29,125			—		—			834,734
Well services		4,623			—			—		—			4,623
General and administrative		94,532			1,575			—		(18,161	)(f)		71,466
										(6,480	)(g)
Depreciation, depletion and amortization		120,246			2,391			15,207		8,068	(e)		145,912

Total costs and expenses		1,129,982			33,091			50,822		(16,573	)		1,197,322

OPERATING INCOME (LOSS)		35,915			(1,215	)		26,879		16,692			78,271
Interest expense		(53,341	)		(2,499	)		—		2,499	(h)		(71,950	)
										(5,340	)(i)
										(339	)(j)
										(1,359	)(k)
										(11,673	)(l)
										(1,303	)(m)
										(1,506	)(n)
										(344	)(o)
										3,255	(p)
Gain (loss) on asset sales and disposal		(2,893	)		269			—		—			(2,624	)
Loss on early extinguishment of debt		(26,601	)		—			—		—			(26,601	)

NET INCOME (LOSS) BEFORE TAX		(46,920	)		(3,445	)		26,879		582			(22,904	)


Income tax benefit		37			—			—		—			37

NET INCOME (LOSS)		(46,883	)		(3,445	)		26,879		582			(22,867	)
(Income) loss attributable to non-controlling interests		26,040			—			—		(5,646	)(q)		9,970
										(10,424	)(r)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS	$	(20,843	)	$	(3,445	)	$	26,879	$	(15,488	)	$	(12,897	)

NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(0.41	)									$	(0.25	)

Diluted	$	(0.41	)									$	(0.25	)

WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,375											51,375

Diluted		51,375											51,375

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2012

(in thousands, except per unit data)

(Unaudited)


			For the Period from January 1 to April 30, 2012		For the Period from January 1 to July 25, 2012		For the Period from January 1 to December 20, 2012			For the Period from January 1 to December 20, 2012		For the Year Ended December 31, 2012			For the Year Ended December 31, 2012
	Historical		Carrizo		Titan		DTE			Cardinal		Teak			EP Energy		Adjustments			Pro Forma
REVENUES:
Gas and oil production	$	92,901	$	6,878	$	10,938	$	53,060		$	—	$	—		$	129,097	$	—		$	292,874
Well construction and completion		131,496		—		—		—			—		—			—		—			131,496
Gathering and processing		1,219,815		—		—		—			66,062		27,353			—		197,773	(s)		1,511,003
Administration and oversight		11,810		—		—		—			—		—			—		—			11,810
Well services		20,041		—		—		—			—		—			—		—			20,041
Gain on mark-to-market derivatives		31,940		—		—		—			—		—			—		—			31,940
Other, net		13,440		—		68		(187	)		1,769		(1,351	)		—		337	(t)		14,076

Total revenues		1,521,443		6,878		11,006		52,873			67,831		26,002			129,097		198,110			2,013,240

COSTS AND EXPENSES:
Gas and oil production		26,624		4,278		4,470		21,295			—		—			74,250		—			130,917
Well construction and completion		114,079		—		—		—			—		—			—		—			114,079
Gathering and processing		1,009,100		—		—		—			26,175		22,728			—		197,773	(s)		1,255,776
Well services		9,280		—		—		—			—		—			—		—			9,280
General and administrative		165,777		—		3,284		7,091			5,719		4,167			—		(15,372	)(f)		149,191
																		(21,475	)(g)
Chevron transaction expense		7,670		—		—		—			—		—			—		—			7,670
Depreciation, depletion and amortization		142,611		—		11,511		22,438			14,837		3,164			68,449		5,491	(u)		300,029
																		69	(v)
																		31,459	(t)
Asset impairment		9,507		—		—		—			—		—			—		—			9,507

Total costs and expenses		1,484,648		4,278		19,265		50,824			46,731		30,059			142,699		197,945			1,976,449


OPERATING INCOME (LOSS)		36,795		2,600	(8,259	)	2,049		21,100		(4,057	)	(13,602	)	165			36,791
Interest expense		(46,520	)	—	(1,683	)	(5,565	)	(2,955	)	(4,849	)	—		(551	)(w)		(146,144	)
															(5,441	)(x)
															(265	)(y)
															(7,058	)(z)
															(836	)(aa)
															551	(bb)
															265	(bb)
															7,058	(bb)
															(21,314	)(cc)
															7,804	(dd)
															(29,395	)(ee)
															(1,504	)(ff)
															(3,587	)(k)
															(23,345	)(l)
															(3,011	)(n)
															(688	)(o)
															(3,255	)(p)
Loss on asset sales and disposal		(6,980	)	—	—		—		—		—		—		—			(6,980	)
Loss on early extinguishment of debt		—		—	(810	)	—		—		—		—		—			(810	)

NET INCOME (LOSS) BEFORE TAX		(16,705	)	2,600	(10,752	)	(3,516	)	18,145		(8,906	)	(13,602	)	(84,407	)		(117,143	)
Income tax expense (benefit)		176		—	—		—		845		—		—		(2,238	)(gg)		(1,217	)

NET INCOME (LOSS)		(16,881	)	2,600	(10,752	)	(3,516	)	17,300		(8,906	)	(13,602	)	(82,169	)		(115,926	)
(Income) loss attributable to non-controlling interests		(35,532	)	—	—		—		(993	)	—		—		1,757	(t)		29,111
															48,304	(r)
															15,575	(q)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS		(52,413	)	2,600	(10,752	)	(3,516	)	16,307		(8,906	)	(13,602	)	(16,533	)		(86,815	)

NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(1.02	)														$	(1.69	)

Diluted	$	(1.02	)														$	(1.69	)

WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,327																51,327

Diluted		51,327																51,327

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(a)

To reflect the preliminary purchase price allocation of the EP Energy Acquisition. Due to the recent date of the EP Energy Acquisition, the purchase price allocation for the assets acquired and liabilities assumed is based upon estimated fair values, which are subject to adjustment and could change significantly as ARP continues to evaluate this preliminary allocation.

(b)

To reflect (i) $248.2 million of gross proceeds from the offering of 9.25% ARP Senior Notes in a private placement transaction at a discount of 99.297%; (ii) net borrowings of $371.1 million under ARP’s revolving credit facility; and (iii) net proceeds of $86.6 million of ARP’s Class C Preferred Units to the Partnership.

(c)

To reflect the partial application of borrowings under ARP’s revolving credit facility for (i) the payment of $15.1 million of revolving credit facility fees, which will be amortized over the remaining term of ARP’s respective debt instrument; (ii) the payment of $5.5 million of fees related to issuance of the 9.25% ARP Senior Notes; and (iii) ARP’s payment of costs of $5.6 million related to the EP Energy Acquisition, which are expensed as incurred and are allocated between common limited partners’ interests and non-controlling interests.

(d)	To reflect the consummation of the EP Energy Acquisition by ARP through the transfer to EP Energy of cash consideration of $705.9 million.

(e)	To reflect incremental depreciation and amortization expense related to the fair value assessment of the assets acquired in the TEAK acquisition, including the basis difference in the fair value of equity method investments acquired.

(f)	To reflect the adjustment to general and administrative expense to exclude APL’s acquisition-related costs incurred related to the acquisitions consummated per the pro forma financial statements.

(g)	To reflect the adjustment to general and administrative expense to exclude ARP’s acquisition-related costs incurred related to the acquisitions consummated per the pro forma financial statements.

(h)	To reflect the adjustment to interest expense for TEAK’s repayment of debt from the net proceeds received on the sale of assets.

(i)

To reflect the adjustment to interest expense to partially finance the TEAK acquisition with the issuance of $400.0 million of APL’s 4.75% Senior Notes offset by the reduction in borrowings of $154.5 million on APL’s revolving credit facility at an interest rate of 2.5% with funds from APL’s 4.75% Senior Notes.

(j)

To reflect the amortization of deferred financing costs incurred related to (i) the issuance of APL’s 4.75% Senior Notes; and (ii) the amendment to APL’s revolving credit facility to provide for (a) the TEAK acquisition to be a permitted investment; (b) for the joint ventures owned by TEAK to not be required to be guarantors nor provide security interests in their assets; and (c) for the revision of the calculation of the compliance calculations.

(k)	To reflect the adjustment to interest expense related to the borrowings under ARP’s revolving credit facility to partially fund the acquisition of assets from EP Energy based on the interest rate of 2.0%.

(l)	To reflect the adjustment to interest expense from the issuance of the 9.25% ARP Senior Notes and the amortization of the debt discount associated with the 9.25% ARP Senior Notes.

(m)	To reflect the adjustment to interest expense on the 7.75% ARP Senior Notes issued on January 23, 2013.

(n)	To reflect the amortization of deferred financing costs incurred as a result of the EP Acquisition related to ARP’s revolving credit facility over the remainder of the facility’s respective term.

(o)	To reflect the amortization of deferred financing costs related to the 9.25% ARP Senior Notes.

(p)

To reflect the adjustment to interest expense for the accelerated amortization of deferred financing costs associated with the retirement of ARP’s term loan facility and a portion of the outstanding indebtedness under ARP’s revolving credit facility with a portion of the proceeds from the issuance of the 7.75% ARP Senior Notes.

(q)

To reflect the adjustment of non-controlling interests in the net income (loss) of APL as a result of the pro forma statement of operations adjustments previously noted. The allocation of APL net income (loss) to non-controlling interests is based upon the general partner’s and limited partners’ relative ownership interests in APL.

(r)

To reflect the adjustment of non-controlling interests in the net income (loss) of ARP as a result of the pro forma statement of operations adjustments previously noted. The allocation of ARP net income (loss) to non-controlling interests is based upon the general partner’s and limited partners’ relative ownership interests subsequent to the transfer of assets to ARP on March 5, 2012, as well as required minimum distributions to preferred limited partners.

(s)

To reclassify natural gas and liquids costs associated to the Cardinal acquisition revenues. Based upon APL’s portfolio of contracts, APL expects to report the revenues and costs under the acquired contracts on a gross basis. Under guidance in the Financial Accounting Standards Board’s Accounting Standards Codification (“ASC”) 605 – Revenue Recognition, APL presents sales of natural gas, natural gas liquids and condensate and the related cost of goods sold as gross values on its consolidated statements of operations, based upon the assessment that APL acts as a “Principal” as defined by the ASC; while Cardinal presented revenues net of costs based upon the assessment that Cardinal acted as an “Agent”, as defined by the ASC. There is no impact on the reported net income (loss) as a result of this adjustment.

(t)

To reflect incremental depreciation and amortization expense related to the fair value assessment of the assets acquired, in the TEAK acquisition and the Cardinal acquisition, including a fair value assessment of the non-controlling interest in the property, plant and equipment and intangible assets and the basis difference in equity method investments.

(u)	To reflect incremental depreciation, depletion and amortization expense, using the units-of-production method, related to the oil and natural gas properties acquired by ARP.

(v)	To reflect incremental accretion expense related to $3.9 million of asset retirement obligations on oil and natural gas properties acquired by ARP.

(w)	To reflect the adjustment to interest expense to finance the $67.5 million of borrowings under ARP’s revolving credit facility to partially fund ARP’s acquisition of assets from Carrizo based on the interest rate of 2.5%.

(x)	To reflect the amortization of deferred financing costs incurred as a result of the Carrizo and DTE acquisitions related to ARP’s revolving credit facility and term loan credit facility over the remainder of the respective terms.

(y)	To reflect the adjustment to interest expense to finance the $18.8 million of borrowings under ARP’s revolving credit facility to partially fund ARP’s acquisition of Titan based on the interest rate of 2.5%.

(z)

To reflect the adjustment to interest expense resulting from borrowings of $75.4 million under ARP’s term loan credit facility and $18.3 million under ARP’s revolving credit facility, both of which were used by ARP to finance the DTE acquisition and related acquisition and financing costs, at a current interest rate of 7.8%.

(aa)	To reflect the amortization of deferred financing costs related to the 7.75% ARP Senior Notes.

(bb)	To reflect the adjustment to interest expense resulting from the retirement of ARP’s term loan credit facility and repayment of amounts outstanding under ARP’s revolving credit facility with proceeds from the 7.75% ARP Senior Notes.

(cc)	To reflect the adjustment to interest expense from the issuance of the 7.75% ARP Senior Notes.

(dd)	To reflect the adjustment to interest expense and other costs for Cardinal’s and TEAK’s repayment of debt from the net proceeds received on the sale of assets.

(ee)

To reflect the adjustment to interest expense to (i) partially finance the Cardinal acquisition with the issuance of $175.0 million of APL’s 6.625% Senior Notes and the additional borrowings of $105.8 million on APL’s revolving credit facility at an interest rate of 2.46%, less the accretion of the $5.3 million premium received on the issuance of APL’s 6.625% Senior Notes and (ii) partially finance the TEAK acquisition with the issuance of $400.0 million of APL’s 4.75% Senior Notes offset by the reduction in borrowings of $154.5 million on APL’s revolving credit facility at an interest rate of 2.5% with funds from APL’s 4.75% Senior Notes.

(ff)

To reflect the amortization of deferred financing costs incurred related to (i) the issuance of APL’s 6.625% Senior Notes; (ii) the issuance of APL’s 4.75% Senior Notes; (iii) the amendment to APL’s revolving credit facility to provide for the Cardinal acquisition to be a permitted investment and for Centrahoma to not be required to be a guarantor nor provide a security interest in its assets; and (iv) the amendment to APL’s revolving credit facility to provide for (a) the TEAK acquisition to be a permitted investment; (b) for the joint ventures owned by TEAK to not be required to be guarantors nor provide security interests in their assets; and (c) for the revision of the calculation of the compliance calculations.

(gg)	To reflect APL’s income tax impact of the incremental depreciation and amortization expense recognized related to APL Arkoma, Inc., (previously known as Cardinal Arkoma, Inc.), a corporate subsidiary acquired through the Cardinal acquisition.

(hh)

The following tables set forth certain unaudited pro forma information concerning ARP’s proved oil, natural gas and natural gas liquids reserves for the years ended December 31, 2012 and 2011, giving effect to the Properties acquired from EP Energy as if they had occurred on January 1, 2011. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development costs. The following reserve data represent estimates only and should not be construed as being precise.

Proved Gas and Oil Reserve Quantities

The pro forma net proved gas and oil reserves and changes in net proved gas and oil reserves attributable to the Properties are summarized below:


	Historical			EP Energy			Pro Forma
	Natural Gas (Mcf)
Balance, January 1, 2011		176,065,003			783,356,000			959,421,003
Extensions, discoveries and other additions		9,966,952			18,780,000			28,746,952
Sales of reserves in-place		(990	)		—			(990	)
Purchase of reserves in-place		586,662			—			586,662
Transfers to limited partnerships		(6,042,432	)		—			(6,042,432	)
Revisions⁽⁴⁾		(11,436,615	)		14,150,000			2,713,385
Production		(11,462,149	)		(50,505,000	)		(61,967,149	)

Balance, December 31, 2011		157,676,431			765,781,000			923,457,431
Extensions, discoveries and other additions		6,756,817			1,705,000			8,461,817
Sales of reserves in-place		—			—			—
Purchase of reserves in-place		462,504,519			—			462,504,519
Transfers to limited partnerships		—			—			—
Revisions⁽⁵⁾		(27,760,192	)		(164,020,000	)		(191,780,192	)
Production		(25,403,318	)		(47,030,000	)		(72,433,318	)

Balance, December 31, 2012		573,774,257			556,436,000			1,130,210,257
Proved developed reserves at:
January 1, 2011		137,393,017			554,906,000			692,299,017
December 31, 2011		138,403,225			545,237,000			683,640,225
December 31, 2012		338,655,324			431,502,000			770,157,324
Proved undeveloped reserves at:
January 1, 2011		38,671,986			228,450,000			267,121,986
December 31, 2011		19,273,206			220,544,000			239,817,206
December 31, 2012		235,118,932			124,934,000			360,052,932


	Historical			EP Energy		Pro Forma
	Oil (Bbl)⁽¹⁾
Balance, January 1, 2011		1,832,535			—		1,832,535
Extensions, discoveries and other additions		8,217			—		8,217
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		2,216			—		2,216
Transfers to limited partnerships		—			—		—
Revisions⁽⁴⁾		77,661			—		77,661
Production		(274,330	)		—		(274,330	)

Balance, December 31, 2011		1,646,299			—		1,646,299
Extensions, discoveries and other additions		10,688			—		10,688
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		7,485,998			—		7,485,998
Transfers to limited partnerships		—			—		—
Revisions		(153,413	)		—		(153,413	)
Production		(120,736	)		—		(120,736	)

Balance, December 31, 2012		8,868,836			—		8,868,836
Proved developed reserves at:
January 1, 2011		1,832,535			—		1,832,535
December 31, 2011		1,638,083			—		1,638,083
December 31, 2012		3,400,447			—		3,400,447
Proved undeveloped reserves at:
January 1, 2011		—			—		—
December 31, 2011		8,216			—		8,216
December 31, 2012		5,468,389			—		5,468,389


	Historical			EP Energy		Pro Forma
	Natural Gas Liquids (Bbl)⁽¹⁾
Balance, January 1, 2011		—			—		—
Extensions, discoveries and other additions		—			—		—
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		—			—		—
Transfers to limited partnerships		—			—		—
Revisions		—			—		—
Production		—			—		—

Balance, December 31, 2011		—			—		—
Extensions, discoveries and other additions		—			—		—
Sales of reserves in-place		—			—		—
Purchase of reserves in-place		16,212,356			—		16,212,356
Transfers to limited partnerships		—			—		—
Revisions⁽⁵⁾		206,091			—		206,091
Production		(356,550	)		—		(356,550	)

Balance, December 31, 2012		16,061,897			—		16,061,897
Proved developed reserves at:
January 1, 2011		—			—		—
December 31, 2011		—			—		—
December 31, 2012		7,884,778			—		7,884,778
Proved undeveloped reserves at:
January 1, 2011		—			—		—
December 31, 2011		—			—		—
December 31, 2012		8,177,120			—		8,177,120

(1)	Oil includes NGL information for the year ended December 31, 2011, which was less than 500 MBbls.

Standardized Measure

The pro forma standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties is as follows (in thousands):


	For the Year Ended December 31, 2012
	Historical			EP Energy			Pro Forma
Future cash inflows	$	2,930,514		$	1,321,983		$	4,252,497
Future production costs		(1,185,084	)		(738,248	)		(1,923,332	)
Future development costs		(441,423	)		(163,469	)		(604,892	)

Future net cash flows		1,304,007			420,266			1,724,273
Less 10% annual discount for estimated timing of cash flows		(680,331	)		(201,674	)		(882,005	)

Standardized measure of discounted future net cash flows	$	623,676		$	218,592		$	842,268


	For the Year Ended December 31, 2011
	Historical			EP Energy			Pro Forma
Future cash inflows	$	949,286		$	2,822,400		$	3,771,686
Future production costs		(425,493	)		(1,204,952	)		(1,630,445	)
Future development costs		(27,266	)		(298,624	)		(325,890	)

Future net cash flows		496,527			1,318,824			1,815,351
Less 10% annual discount for estimated timing of cash flows		(276,668	)		(726,648	)		(1,003,316	)

Standardized measure of discounted future net cash flows	$	219,859		$	592,176		$	812,035

FASB requirements for gas and oil reserve estimation and disclosure require that reserve estimates and future cash flows be based on the average market prices for sales of gas and oil on the first calendar day of each month during the year. The average prices used for 2012 and 2011 under these rules were $2.76 and $4.12 per Mcf.

Changes in Standardized Measure

Pro forma changes in the standardized measure of discounted future net cash flows before income taxes related to the proved gas and oil reserves of the Properties are as follows:


	Year Ended December 31, 2012
	Historical			EP Energy			Pro Forma
Balance, beginning of year	$	219,859		$	592,176		$	812,035
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(54,969	)		(78,153	)		(133,122	)
Net changes in prices and production costs		(87	)		(349,076	)		(349,163	)
Revisions of previous quantity estimates		(6,378	)		(94,806	)		(101,184	)
Development costs incurred		575			2,000			2,575
Changes in future development costs		—			73,781			73,781
Transfers to limited partnerships		—			—			—
Extensions, discoveries, and improved recovery less related costs		64			540			604
Purchases of reserves in-place		510,467			—			510,467
Sales of reserves in-place		—			—			—
Accretion of discount		21,986			72,665			94,651
Estimated settlement of asset retirement obligations		(2,823	)		—			(2,823	)
Estimated proceeds on disposals of well equipment		3,806			—			3,806
Changes in production rates (timing) and other		(68,824	)		(535	)		(69,359	)

Outstanding, end of year	$	623,676		$	218,592		$	842,268


	Year Ended December 31, 2011
	Historical			EP Energy			Pro Forma
Balance, beginning of year	$	236,630		$	660,619		$	897,249
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(46,304	)		(137,357	)		(183,661	)
Net changes in prices and production costs		(34	)		(26,668	)		(26,702	)
Revisions of previous quantity estimates		757			16,432			17,189
Development costs incurred		1,842			22,392			24,234
Changes in future development costs		(3,591	)		(15,697	)		(19,288	)
Transfers to limited partnerships		(8,022	)		—			(8,022	)
Extensions, discoveries, and improved recovery less related costs		14,923			10,650			25,573
Purchases of reserves in-place		736			—			736
Sales of reserves in-place		(1	)		—			(1	)
Accretion of discount		23,663			80,681			104,344
Estimated settlement of asset retirement obligations		(3,105	)		—			(3,105	)
Estimated proceeds on disposals of well equipment		3,363			—			3,363
Changes in production rates (timing) and other		(998	)		(18,876	)		(19,874	)

Outstanding, end of year	$	219,859		$	592,176		$	812,035

Attached files

Targa Energy LP Reports

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