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

Attached files

file	filename
8-K/A - 8-K/A - Targa Energy LP	d771746d8ka.htm
EX-23.1 - EX-23.1 - Targa Energy LP	d771746dex231.htm
EX-99.1 - EX-99.1 - Targa Energy LP	d771746dex991.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 oil and gas assets from EP Energy E&P Company, L.P. (“EP Energy”) for $709.6 million in cash (the “EP Energy Acquisition”), and (ii) a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely Field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (“Merit Energy”) for $420.0 million in cash (the “Rangely Acquisition”), funded with borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior unsecured notes due on January 15, 2021 (“7.75% ARP Senior Notes”) for net proceeds of approximately $97.3 million, and the issuance of an additional 15.5 million ARP common limited partner units (including approximately 2.0 million units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit yielding net proceeds of approximately $297.5 million, and (B) (i) Atlas Pipeline Partners, L.P.’s (“APL”) May 7, 2013 acquisition from TEAK Midstream, LLC (“TEAK”) of 100% of the outstanding member and other ownership interests of TEAK for approximately $1.0 billion (the “TEAK Acquisition”). 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 three months ended March 31, 2014 and the year ended December 31, 2013 assume the following transactions had occurred as of January 1, 2013. In addition, the pro forma consolidated balance sheet as of March 31, 2014 reflects the following transactions as if they had occurred on March 31, 2014:

•

the EP Energy Acquisition for cash consideration of $709.6 million;

•

the issuance of 6.3 million ARP common limited partner units (including 0.8 million units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit yielding net proceeds of approximately $190.1 million;

•

the issuance of an additional $100.0 million of 7.75% ARP Senior Notes for net proceeds of approximately $97.3 million;

•

the Rangely Acquisition for cash consideration of $420.0 million, which was funded through borrowings under ARP’s revolving credit facility and the related issuance of approximately 15.5 million ARP common limited partner units (including approximately 2.0 million units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit yielding net proceeds of approximately $297.5 million; and

•

the TEAK Acquisition for approximately $1.0 billion.

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 Rangely Acquisition. 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, 2013, which were presented inclusive of the EP Energy Acquisition, were included with the Partnership’s annual filing on Form 10-K for the year ended December 31, 2013 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.

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED BALANCE SHEET

MARCH 31, 2014

(in thousands)

(Unaudited)


			Acquisition
	Historical		Rangely				Adjustments					Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	24,779	$	—			$	420,000		(b	)	$	153,857
								129,078		(c	)
								(420,000	)	(e	)
Accounts receivable		327,031		—				—					327,031
Current portion of derivative asset		161		—				—					161
Prepaid expenses and other		42,213		4,041	(a	)		—					46,254

Total current assets		394,184		4,041				129,078					527,303
PROPERTY, PLANT AND EQUIPMENT, NET		5,024,505		417,264	(a,u	)		—					5,441,769
INTANGIBLE ASSETS, NET		655,679		—				—					655,679
INVESTMENT IN JOINT VENTURE		269,058		—				—					269,058
GOODWILL, NET		402,180		—				—					402,180
LONG-TERM DERIVATIVE ASSET		28,325		—				—					28,325
OTHER ASSETS, NET		124,305		—				8,253		(d	)		134,808
								2,250		(d	)

	$	6,898,236	$	421,305			$	139,581				$	7,459,122

LIABILITIES AND PARTNERS’ CAPITAL/EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	2,794	$	—			$	—				$	2,794
Accounts payable		187,899		—				—					187,899
Accrued producer liabilities		191,066		—				—					191,066
Current portion of derivative liability		36,929		—				—					36,929
Accrued interest		21,689		—				—					21,689
Accrued well drilling and completion costs		72,158		—				—					72,158
Accrued liabilities		76,475		—				—					76,475

Total current liabilities		589,010		—				—					589,010
LONG-TERM DEBT, LESS CURRENT PORTION		2,830,337		—				97,250		(b	)		2,972,150
								25,269		(b	)
								19,294		(d	)
DEFERRED INCOME TAXES, NET		32,892		—				—					32,892
ASSET RETIREMENT OBLIGATIONS		92,927		1,305	(a	)		—					94,232


			Acquisition
	Historical		Rangely				Adjustments					Pro Forma
OTHER LONG-TERM LIABILITIES		12,702		—				—					12,702
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL/EQUITY:
Common limited partners’ interests		345,045		—				(2,397	)	(d	)		342,648
Equity		—		420,000	(a	)		(420,000	)	(e	)		—
Accumulated other comprehensive income		2,140		—				—					2,140

		347,185		420,000				(422,397	)				344,788
Non-controlling interests		2,993,183		—				(6,394	)	(d	)		3,413,348
								297,481		(b	)
								129,078		(c	)

Total partners’ capital/equity		3,340,368		420,000				(2,232	)				3,758,136

	$	6,898,236	$	421,305			$	139,581				$	7,459,122

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(in thousands)

(Unaudited)


				Acquisition
	Historical			Rangely		Adjustments					Pro Forma
REVENUES:
Gas and oil production	$	100,825		$	23,105	$	—				$	123,930
Well construction and completion		49,377			—		—					49,377
Gathering and processing		710,980			—		—					710,980
Administration and oversight		1,729			—		—					1,729
Well services		5,479			—		—					5,479
Loss on mark-to-market derivatives		(8,671	)		—		—					(8,671	)
Other, net		543			—		—					543

Total revenues		860,262			23,105		—					883,367

COSTS AND EXPENSES:
Gas and oil production		38,758			8,247		—					47,005
Well construction and completion		42,936			—		—					42,936
Gathering and processing		604,954			—		—					604,954
Well services		2,482			—		—					2,482
General and administrative		48,402			—		(2,379	)	(f	)		46,023
Depreciation, depletion and amortization		101,278			—		4,418		(g	)		105,715
							19		(h	)

Total costs and expenses		838,810			8,247		2,058					849,115

OPERATING INCOME (LOSS)		21,452			14,858		(2,058	)				34,252
Interest expense		(41,314	)		—		377		(i	)		(43,329	)
							(1,953	)	(j	)
							(369	)	(k	)
							(70	)	(l	)
Loss on asset sales and disposal		(1,603	)		—		—					(1,603	)

NET INCOME (LOSS) BEFORE TAX		(21,465	)		14,858		(4,073	)				(10,680	)
Income tax benefit		(398	)		—		—					(398	)

NET INCOME (LOSS)		(21,067	)		14,858		(4,073	)				(10,282	)
(Income) loss attributable to non-controlling interests		7,142			—		(7,844	)	(m	)		(702	)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS	$	(13,925	)	$	14,858	$	(11,917	)			$	(10,984	)


				Acquisition
	Historical			Rangely	Adjustments	Pro Forma
NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(0.27	)			$	(0.21	)

Diluted	$	(0.27	)			$	(0.21	)

WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,491					51,491

Diluted		51,491					51,491

ATLAS ENERGY, L.P. AND SUBSIDIARIES

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2013

(in thousands, except per unit data)

(Unaudited)


				For the Period from January 1 to July 31, 2013		For the Period from January 1 to May 7, 2013			For the Year Ended December 31, 2013
	Historical			EP Energy		TEAK			Rangely		Adjustments					Pro Forma
REVENUES:
Gas and oil production	$	273,906		$	90,626	$	—		$	91,575	$	—				$	456,107
Well construction and completion		167,883			—		—			—		—					167,883
Gathering and processing		2,139,694			—		36,111			—		—					2,175,805
Administration and oversight		12,277			—		—			—		—					12,277
Well services		19,492			—		—			—		—					19,492
Gain on mark-to-market derivatives		(28,764	)		—		—			—		—					(28,764	)
Other, net		(6,973	)		—		(2,729	)		—		—					(9,702	)

Total revenues		2,577,515			90,626		33,382			91,575		—					2,793,098

COSTS AND EXPENSES:
Gas and oil production		100,178			41,630		—			32,069		—					173,877
Well construction and completion		145,985			—		—			—		—					145,985
Gathering and processing		1,802,618			—		30,694			—		—					1,833,312
Well services		9,515			—		—			—		—					9,515
General and administrative		197,976			—		1,575			—		(24,735	)	(f	)		155,530
												(19,286	)	(n	)
Depreciation, depletion and amortization		308,533			17,742		5,954			—		17,381		(g	)		357,639
												76		(h	)
												7,953		(o	)
Asset impairment		81,880			—		—			—		—					81,880

Total costs and expenses		2,646,685			59,372		38,223			32,069		(18,611	)				2,757,738

OPERATING INCOME (LOSS)		(69,170	)		31,254		(4,841	)		59,506		18,611					35,360
Interest expense		(132,581	)		—		(2,176	)		—		(1,391	)	(i	)		(150,558	)
												(1,303	)	(p	)
												(7,813	)	(j	)
												(1,476	)	(k	)


				For the Period from January 1 to July 31, 2013		For the Period from January 1 to May 7, 2013			For the Year Ended December 31, 2013
	Historical			EP Energy		TEAK			Rangely		Adjustments					Pro Forma
												(280	)	(l	)
												2,176		(q	)
												(5,340	)	(r	)
												(374	)	(s	)
Income (loss) on asset sales and disposal		(2,506	)		—		269			—		—					(2,237	)
Loss on early extinguishment of debt		(26,601	)		—		—			—		—					(26,601	)

NET INCOME (LOSS) BEFORE TAX		(230,858	)		31,254		(6,748	)		59,506		2,810					(144,036	)
Income tax benefit		(2,260	)		—		—			—		—					(2,260	)

NET INCOME (LOSS)		(228,598	)		31,254		(6,748	)		59,506		2,810					(141,776	)
(Income) loss attributable to non-controlling interests		153,231			—		—			—		(4,136	)	(t	)		90,123
												(58,972	)	(m	)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON LIMITED PARTNERS		(75,367	)		31,254		(6,748	)		59,506		(60,298	)				(51,653	)

NET LOSS ATTRIBUTABLE TO COMMON LIMITED PARTNERS PER UNIT:
Basic	$	(1.47	)													$	(1.01	)

Diluted	$	(1.47	)													$	(1.01	)

WEIGHTED AVERAGE COMMON LIMITED PARTNER UNITS OUTSTANDING:
Basic		51,387															51,387

Diluted		51,387															51,387

ATLAS ENERGY, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(a)

To reflect the preliminary purchase price allocation of the Rangely Acquisition. Due to the recent date of the Rangely 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) $97.3 million of net proceeds from the public offering of ARP’s additional $100.0 million 7.75% Senior Notes in a private placement transaction; (ii) borrowings of $25.3 million under ARP’s revolving credit facility; and (iii) net proceeds of $297.5 million from ARP’s issuance of an additional 15.5 million common limited partner units (including approximately 2.0 million units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit.

(c)	To reflect the issuance of 6.3 million ARP common limited partner units (including 0.8 million units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit yielding net proceeds of $129.1 million in March 2014.

(d)

To reflect the partial application of borrowings under ARP’s revolving credit facility for (i) the payment of $8.3 million of ARP revolving credit facility fees, which will be amortized over the remaining term of the respective debt instrument; (ii) the payment of $2.3 million of deferred financing costs related to the issuance of ARP’s additional $100.0 million 7.75% Senior Notes, which will be amortized over the remaining term of the respective debt instrument; and (iii) the payment of costs of $8.8 million related to the acquisitions, which are expensed as incurred and are allocated between common limited partners’ interests and non-controlling interests.

(e)	To reflect the consummation of the Rangely Acquisition through the transfer of cash consideration of $420.0 million.

(f)	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.

(g)	To reflect incremental depreciation, depletion amortization expense related to the acquisition of oil and gas assets in the Rangely Acquisition.

(h)	To reflect incremental accretion expense related to $1.3 million of asset retirement obligations on oil and natural gas properties acquired.

(i)	To reflect the adjustment to interest expense related to the borrowings under ARP’s revolving credit facility to partially fund the acquisition of assets in the Rangely Acquisition based on the interest rate of 2.2%.

(j)	To reflect the adjustment to interest expense from ARP’s additional $100.0 million issuance of 7.75% Senior Notes and the amortization of the debt discount associated with the 7.75% Senior Notes.

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

(l)	To reflect the amortization of deferred financing costs related to ARP’s additional $100.0 million issuance of 7.75% Senior Notes.

(m)

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, as well as required minimum distributions to preferred limited partners.

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

(o)	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.

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

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

(r)

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.

(s)

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.

(t)

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.

(u)

The following tables set forth certain unaudited pro forma information concerning ARP’s proved oil, natural gas and natural gas liquids reserves for the year ended December 31, 2013, giving effect to the Rangely Acquisition as if it had occurred on January 1, 2013. 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

ARP’s pro forma net proved gas and oil reserves and changes in net proved gas and oil reserves attributable to the Rangely Acquisition are summarized below:


	Historical			Rangely Acquisition		Pro Forma
				Natural Gas (Mcf)
Balance, January 1, 2013		573,774,257			—		573,774,257
Extensions, discoveries and other additions		90,098,219			—		90,098,219
Sales of reserves in-place		(2,755,155	)		—		(2,755,155	)
Purchase of reserves in-place		452,683,902			—		452,683,902
Transfers to limited partnerships		(2,485,210	)		—		(2,485,210	)
Revisions⁽⁵⁾		(88,488,497	)		—		(88,488,497	)
Production		(57,993,487	)		—		(57,993,487	)

Balance, December 31, 2013		964,834,029			—		964,834,029
Proved developed reserves at:
January 1, 2013		338,655,324			—		338,655,324
December 31, 2013		727,926,951			—		727,926,951
Proved undeveloped reserves at:
January 1, 2013		235,118,932			—		235,118,932
December 31, 2013		236,907,078			—		236,907,078


	Historical			Rangely Acquisition			Pro Forma
				Oil (Bbl)
Balance, January 1, 2013		8,868,836			19,831,680			28,700,516
Extensions, discoveries and other additions		8,255,531			—			8,255,531
Sales of reserves in-place		—			—			—
Purchase of reserves in-place		1,598			—			1,598
Transfers to limited partnerships		(239,910	)		—			(239,910	)
Revisions		(1,412,359	)		25,584			(1,386,775	)
Production		(485,226	)		(930,748	)		(1,415,974	)

Balance, December 31, 2013		14,988,470			18,926,516			33,914,986
Proved developed reserves at:
January 1, 2013		3,400,447			18,164,413			21,564,860
December 31, 2013		3,458,907			17,480,779			20,939,686
Proved undeveloped reserves at:
January 1, 2013		5,468,389			1,667,267			7,135,656
December 31, 2013		11,529,563			1,445,737			12,975,300


	Historical			Rangely Acquisition			Pro Forma
				Natural Gas Liquids (Bbl)
Balance, December 31, 2013		16,061,897			1,352,990			17,414,887
Extensions, discoveries and other additions		8,197,272			—			8,197,272
Sales of reserves in-place		(4,625	)		—			(4,625	)
Purchase of reserves in-place		55,187			—			55,187
Transfers to limited partnerships		(258,381	)		—			(258,381	)
Revisions⁽⁵⁾		(3,826,744	)		30,524			(3,796,220	)
Production		(1,267,590	)		(101,642	)		(1,369,232	)

Balance, December 31, 2013		18,957,016			1,281,872			20,238,888
Proved developed reserves at:
January 1, 2013		7,884,778			1,352,990			9,237,768
December 31, 2013		7,676,389			1,281,872			8,958,261
Proved undeveloped reserves at:
January 1, 2013		8,177,120			—			8,177,120
December 31, 2013		11,280,627			—			11,280,627

Standardized Measure

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


	For the Year Ended December 31, 2013
	Historical			Rangely Acquisition			Pro Forma
Future cash inflows	$	5,145,835		$	1,798,238		$	6,944,073
Future production costs		(2,347,592	)		(784,622	)		(3,132,214	)
Future development costs		(746,725	)		(83,848	)		(830,573	)

Future net cash flows		2,051,518			929,768			2,981,286
Less 10% annual discount for estimated timing of cash flows		(1,012,326	)		(558,029	)		(1,570,355	)

Standardized measure of discounted future net cash flows	$	1,039,192		$	371,739		$	1,410,931

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 2013 under these rules were $3.67 per Mcf of natural gas and $96.78 per barrel of oil.

Changes in Standardized Measure

ARP 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 Rangely Acquisition are as follows:


	Year Ended December 31, 2013
	Historical			Rangely Acquisition			Pro Forma
Balance, beginning of year	$	623,676		$	372,338		$	996,014
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(167,581	)		(59,506	)		(227,087	)
Net changes in prices and production costs		85,191			(803	)		84,388
Revisions of previous quantity estimates		(1,881	)		1,125			(756	)
Development costs incurred		27,245			17,306			44,551
Changes in future development costs		(21,579	)		(6,500	)		(28,079	)
Transfers to limited partnerships		(53,392	)		—			(53,392	)
Extensions, discoveries, and improved recovery less related costs		143,338			—			143,338
Purchases of reserves in-place		473,058			—			473,058
Sales of reserves in-place		(2,053	)		—			(2,053	)
Accretion of discount		62,368			37,234			99,602
Estimated settlement of asset retirement obligations		(18,858	)		—			(18,858	)
Estimated proceeds on disposals of well equipment		17,052			—			17,052
Changes in production rates (timing) and other		(127,392	)		10,545			(116,847	)

Outstanding, end of year	$	1,039,192		$	371,739		$	1,410,931

Targa Energy LP - FORM 8-K/A - EX-99.2 - August 7, 2014

Attached files

Targa Energy LP Reports