Marathon Oil Reports Second Quarter 2019 Results

$250 Million Share Repurchases Year-to-Date Supported by Continued Strong Free Cash Flow; Buyback Authorization Raised to $1.5 Billion

News provided by

Marathon Oil Corporation

Aug 07, 2019, 16:30 ET

HOUSTON, Aug. 7, 2019 /PRNewswire/ -- Marathon Oil Corporation (NYSE: MRO) today reported second quarter 2019 net income of $161 million, or $0.20 per diluted share, which includes the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. Adjusted net income was $189 million, or $0.23 per diluted share. Net operating cash flow was $797 million, or $771 million before changes in working capital.

Highlights

$137 million of organic free cash flow post-dividend, bringing year-to-date organic free cash flow to $217 million
$250 million of year-to-date share repurchases in addition to $82 million of dividend payments; approximately 25% of year-to-date net operating cash flow returned to shareholders
Board of Directors approved increase of the share repurchase authorization to $1.5 billion
Development capital spend of $636 million second quarter and $1.2 billion year-to-date; annual $2.4 billion development capital budget remains unchanged
U.S. oil production averaged 192,000 net bopd during second quarter, up 17% from year-ago quarter, divestiture-adjusted, and above top end of guidance range
Total Company oil production averaged 218,000 net bopd during second quarter, up 14% from year-ago quarter, divestiture-adjusted
Closed on sale of U.K. business July 1, removing $966 million of asset retirement obligations; coupled with second quarter close on sale of remaining block in Kurdistan, these two complete country exits simplify the international portfolio to the free cash flow generating integrated business in Equatorial Guinea
Strong financial position with investment grade rating at all three primary credit ratings agencies reflecting peer leading leverage metrics and free cash flow breakeven oil price

"Second quarter featured exceptional operational performance across our advantaged multi-basin portfolio driving compelling bottom-line financial outcomes," said Chairman, President and CEO Lee Tillman. "Through differentiated execution, we're improving our corporate returns, generating meaningful free cash flow, and returning significant capital back to our shareholders. Already in 2019, we've returned about 25% of our net operating cash flow back to our shareholders. Since the beginning of 2018, we have repurchased $950 million of our own shares, funded entirely by post-dividend organic free cash flow, equating to about a 6% reduction in our share count. The refreshed $1.5 billion share repurchase authorization positions us well to continue executing against our well-defined strategic framework. This is our sixth consecutive quarter of organic free cash flow generation, and our underlying free cash flow momentum only continues to improve. We believe our unwavering commitment to capital discipline and low enterprise breakeven oil price delivers success across a wide range of commodity price environments."

United States (U.S.)
U.S. production averaged 332,000 net barrels of oil equivalent per day (boed) for second quarter 2019, including 192,000 net barrels of oil per day (bopd), both above the top end of the second quarter guidance ranges. Oil production was up 17% from the year-ago quarter on a divestiture-adjusted basis. U.S. unit production costs were $4.89 per barrel of oil equivalent (boe), down 14% from the year-ago quarter, the lowest quarterly average unit production costs since becoming an independent exploration and production company in 2011.

EAGLE FORD: Marathon Oil's Eagle Ford production averaged 109,000 net boed in the second quarter 2019. The Company brought 41 gross Company-operated wells to sales in the quarter. Second quarter activity featured impressive results across the Company's acreage position. In Karnes County, a four-well pad achieved an average 30-day initial production (IP) rate of 3,230 boed (67% oil), establishing a new pad record for the Company in the Eagle Ford. The Company continued to deliver strong results from the expanded core of Atascosa County, where 15 wells achieved an average 30-day IP rate of 1,860 boed (81% oil). As the Company continues its efforts to uplift performance outside of the Karnes and Atascosa core, enhanced completion techniques were successfully applied in Gonzales County, where a six-well pad achieved an average 30-day IP rate of 1,600 boed (70% oil). Despite a majority of wells to sales outside of Karnes County during second quarter, the Eagle Ford asset achieved a quarterly record for average 30 day initial well productivity, while continuing to drive a trend of lower completed well costs per lateral foot.

BAKKEN: Marathon Oil's Bakken production averaged 104,000 net boed in the second quarter 2019. The Company brought 30 gross Company-operated wells to sales, balanced between Myrmidon and Hector. The Company continues to deliver impressive capital efficiency, highlighted by a six-well pad in Myrmidon that delivered an average 30-day IP rate of 3,160 boed (78% oil) at an average completed well cost of $5.3 million. The average completed well cost for all of Marathon Oil's second quarter wells was $5.2 million, down approximately 15% in comparison to the 2018 average.

OKLAHOMA: Marathon Oil's Oklahoma production averaged 82,000 net boed in the second quarter 2019. The Company brought 18 gross Company-operated wells to sales. Marathon Oil continues to deliver strong results from the overpressured STACK, where the eight-well per section Mike Stroud infill achieved an average 30-day IP rate of 2,480 boed (38% oil) with average completed well costs more than 30% below the previously drilled parent well. The Company continues to make significant progress in reducing its cost structure and improving efficiencies. Marathon Oil's two most recent overpressured STACK infills achieved an average completed well cost of $6.3 million normalized to a 10,000 foot lateral.

NORTHERN DELAWARE: Marathon Oil's Northern Delaware production averaged 28,000 net boed in the second quarter 2019. The Company brought 16 gross Company-operated wells to sales, including a mix of development and delineation wells in both the Malaga and Red Hills areas. Marathon Oil continues to make significant progress in reducing its cost structure and improving margins, with second quarter cash costs down approximately 10% sequentially on a per boe basis, 100% of water on pipe for all second quarter wells to sales, and a rising percentage of total oil production on pipe. Second quarter again featured strong Upper Wolfcamp productivity in Malaga, where 11 development wells achieved an average 30-day IP rate of 1,520 boed (63% oil), or 345 boed per one thousand foot lateral, with completed well costs per lateral foot 5% below the 2018 average.

International
International production averaged 103,000 net boed for second quarter 2019. During the quarter, E.G. production returned to normal levels after successful completion of the planned triennial turnaround during first quarter 2019. Second quarter 2019 International unit production costs averaged $4.72 per boe.

During the second quarter, the Company closed on the sale of its 15% participating interest in the Atrush Block in Kurdistan, marking a complete country exit. Subsequent to quarter end on July 1, the Company closed on the sale of its U.K business, representing the tenth country exit since 2013.

Excluding Kurdistan and U.K operations, second quarter international production averaged 91,000 net boed with unit production costs of $2.21 per boe. As of July 1, the Company's international operations are limited to the integrated business in Equatorial Guinea.

Cash Flow, Development Capital and Resource Capture
Net cash provided by operations was $797 million during second quarter 2019, or $771 million before changes in working capital.

Second quarter development capital expenditures were $636 million, with year-to-date development capital of $1.2 billion. The Company's 2019 development capital budget remains unchanged at $2.4 billion.

Outside of the development capital budget, second quarter resource play leasing and exploration (REx) capital expenditures were $37 million, with year-to-date expenditures of $74 million. The Company's 2019 REx capital budget remains unchanged at $200 million.

Organic free cash flow during second quarter totaled $137 million post-dividend, bringing year-to-date organic free cash flow generation to $217 million.

Production Guidance
For third quarter 2019, the Company forecasts total U.S. oil production of 190,000 to 200,000 net bopd. Third quarter 2019 international oil production guidance is 12,000 to 16,000 net bopd, reflecting both the U.K. and Kurdistan asset divestitures. Adjusted full year 2019 production guidance now excludes divested U.K. and Kurdistan volumes for the second half of 2019, but otherwise remains unchanged. There is no change to annual divestiture-adjusted oil production growth guidance of 10% for total Company and 12% for U.S.

Corporate
The Company has executed $250 million of year-to-date share repurchases, returning additional capital to shareholders beyond the $82 million of year-to-date dividend payments. On a year-to-date basis, the Company has returned approximately 25% of net operating cash flow back to shareholders. Since the beginning of 2018, Marathon Oil has repurchased $950 million of its own shares, representing approximately 6% of its outstanding share count, funded entirely by post-dividend organic free cash flow generation of over $1 billion over the same period. The board of directors authorized an increase in the remaining share repurchase authorization to a total of $1.5 billion, representing an increase in authorization of $950 million.

Total liquidity as of June 30 was approximately $4.4 billion, which consisted of $1.0 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion. End of quarter cash and cash equivalents reflect cash balances classified as held for sale associated with U.K. properties, but do not include the $95 million of sales proceeds received upon July 1 close.

Marathon Oil's credit rating was upgraded to investment grade by Moody's Investor's Service on April 24. The Company's credit rating was also upgraded from BBB- to BBB by S&P on June 19. Marathon Oil is rated investment grade at all three primary credit ratings agencies.

The adjustments to net income for second quarter 2019 totaled $28 million before tax, primarily due to impairments and loss on sale associated with asset dispositions, partially offset by the income impact associated with unrealized gains on derivative instruments.

As of August 5, 2019, the Company's open crude hedge positions for 2019 include an average of 80,000 bopd at a weighted average floor price of $56.75 per bbl and a weighted average ceiling price of $74.19 per bbl, hedged through three-way collars. The Company has also hedged 19,945 bopd of 2020 oil production at a weighted average floor price of $55.00 per bbl.

A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, Aug. 7. On Thursday, Aug. 8, at 9:00 a.m. ET, the Company will conduct a question and answer webcast/call, which will include forward-looking information. The live webcast, replay and all related materials will be available at https://www.marathonoil.com/Investors.

Definitions
Organic free cash flow - Operating cash flow before working capital (excluding exploration costs other than well costs), less development capital expenditures, less dividends, plus other.

Non-GAAP Measures
In analyzing and planning for its business, Marathon Oil supplements its use of GAAP financial measures with non-GAAP financial measures, including adjusted net income, adjusted net income per share, net cash provided by operations before changes in working capital, and organic free cash flow because the Company believes this information is useful to investors to help evaluate the Company's financial performance between periods and to compare the Company's performance to certain competitors. Management also uses net cash provided by operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. The Company considers adjusted net income and adjusted net income per share as another way to meaningfully represent the Company's operational performance for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges, dispositions, pension settlements, and other items that could be considered "non-operating" or "non-core" in nature. These non-GAAP financial measures reflect an additional way of viewing aspects of the business that, when viewed with GAAP results may provide a more complete understanding of factors and trends affecting the business and are a useful tool to help management and investors make informed decisions about Marathon Oil's financial and operating performance. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. A reconciliation to their most directly comparable GAAP financial measures can be found in our investor package on our website at www.marathonoil.com and in the tables below. Marathon Oil strongly encourages investors to review the Company's consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

Forward-looking Statements
This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, including without limitation statements regarding the Company's 2019 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, asset sales and acquisitions, leasing and exploration activities, production, oil growth and other plans and objectives for future operations, are forward-looking statements. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," "may," "plan," "project," "seek," "should," "target," "will," "would," or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause actual results to differ materially from those projected, including, but not limited to: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates; risks related to the Company's hedging activities; capital available for exploration and development; drilling and operating risks; well production timing; availability of drilling rigs, materials and labor, including associated costs; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the government or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company's 2018 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.marathonoil.com. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

Media Relations Contact:
Lee Warren: 713-296-4103

Investor Relations Contacts:
Guy Baber: 713-296-1892
John Reid: 713-296-4380

Consolidated Statements of Income (Unaudited)	Three Months Ended
	June 30		Mar. 31		June 30
(In millions, except per share data)	2019		2019		2018
Revenues and other income:
Revenues from contracts with customers	$	1,381	$	1,200	$	1,447
Net gain (loss) on commodity derivatives	16		(91)		(152)
Income from equity method investments	31		11		60
Net gain (loss) on disposal of assets	(8)		42		50
Other income	13		35		12
Total revenues and other income	1,433		1,197		1,417
Costs and expenses:
Production	193		187		205
Shipping, handling and other operating	170		154		126
Exploration	26		59		65
Depreciation, depletion and amortization	605		554		612
Impairments	18		6		34
Taxes other than income	79		72		65
General and administrative	87		94		105
Total costs and expenses	1,178		1,126		1,212
Income from operations	255		71		205
Net interest and other	(64)		(49)		(65)
Other net periodic benefit costs	2		5		—
Income before income taxes	193		27		140
Provision (benefit) for income taxes	32		(147)		44
Net income	$	161	$	174	$	96

Adjusted Net Income
Net income	$	161	$	174	$	96
Adjustments for special items (pre-tax):
Net (gain) loss on disposal of assets	8		(42)		(50)
Proved property impairments	18		6		34
Pension settlement	2		—		2
Unrealized (gain) loss on derivative instruments	(11)		113		45
Other	11		12		(8)
Benefit for income taxes related to special items	—		(7)		7
Adjustments for special items	28		82		30
Adjusted net income (a)	$	189	$	256	$	126
Per diluted share:
Net income	$	0.20	$	0.21	$	0.11
Adjusted net income (a)	$	0.23	$	0.31	$	0.15
Weighted average diluted shares	814		820		855


(a)	Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30		Mar. 31		June 30
(In millions)	2019		2019		2018
Segment income
United States	$	215	$	132	$	123
International	96		61		142
Segment income	311		193		265
Not allocated to segments	(150)		(19)		(169)
Net income	$	161	$	174	$	96
Exploration expenses
United States	$	26	$	59	$	64
International	—		—		1
Total	$	26	$	59	$	65
Cash flows
Net cash provided by operating activities	$	797	$	515	$	767
Minus: changes in working capital	26		(157)		(82)
Net cash provided by operations before changes in working capital (a)	$	771	$	672	$	849

Cash additions to property, plant and equipment	$	(647)	$	(615)	$	(638)


(a)	Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended		Six Months Ended
(In millions)	June 30, 2019		June 30, 2019
Organic Free Cash Flow
Net cash provided by operating activities	$	797	$	1,312
Minus: changes in working capital	26		(131)
Minus: exploration costs other than well costs	(6)		(16)
Development capital expenditures	(636)		(1,205)
Dividends	(41)		(82)
EG LNG return of capital and other	37		45
Organic free cash flow (a)	$	137	$	217


(a)	Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30	Mar. 31	June 30
(mboed)	2019	2019	2018
Net production
United States	332	296	298
International	103	92	121
Total net production	435	388	419

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30	Mar. 31	June 30
(mboed)	2019	2019	2018
Net production
United States	332	296	298
Less: Divestitures (a)	1	—	6
Total divestiture-adjusted United States	331	296	292

International	103	92	121
Less: Divestitures (b)	12	14	18
Total divestiture-adjusted International	91	78	103

Total net production divestiture-adjusted (a)(b)	422	374	395


(a)	The Company closed on the sale of certain United States non-core conventional assets primarily in the Gulf of Mexico in third quarter 2018 and first quarter 2019. The production volumes relating to these dispositions have been removed from all corresponding prior periods to derive the divestiture-adjusted United States net production.
(b)	Divestitures include volumes associated with the sale of our U.K. business, which closed in third quarter 2019, the sale of our non-operated interest in Kurdistan, which closed in second quarter 2019 and third quarter 2018. These production volumes have been removed from historical periods above in arriving at total divestiture-adjusted International net production.

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30	Mar. 31	June 30
	2019	2019	2018
United States - net sales volumes
Crude oil and condensate (mbbld)	190	177	168
Eagle Ford	61	61	63
Bakken	88	79	69
Oklahoma	21	16	18
Northern Delaware	15	15	11
Other United States (a)	5	6	7
Natural gas liquids (mbbld)	64	55	57
Eagle Ford	25	23	22
Bakken	8	7	7
Oklahoma	24	18	24
Northern Delaware	6	6	3
Other United States (a)	1	1	1
Natural gas (mmcfd)	459	392	435
Eagle Ford	139	127	127
Bakken	42	36	35
Oklahoma	223	173	230
Northern Delaware	36	33	18
Other United States (a)	19	23	25
Total United States (mboed)	330	297	298
International - net sales volumes
Crude oil and condensate (mbbld)	30	23	32
Equatorial Guinea	20	12	18
United Kingdom	8	9	10
Other International	2	2	4
Natural gas liquids (mbbld)	10	8	12
Equatorial Guinea	10	8	11
United Kingdom	—	—	1
Natural gas (mmcfd)	403	342	461
Equatorial Guinea	392	330	443
United Kingdom (b)	11	12	18
Total International (mboed)	107	88	121
Total Company - net sales volumes (mboed)	437	385	419
Net sales volumes of equity method investees
LNG (mtd)	5,321	4,636	6,141
Methanol (mtd)	1,134	1,003	1,316
Condensate and LPG (boed)	11,080	9,890	12,689


(a)	The three months ended June 30, 2018 includes sales volumes from the sale of certain United States non-core conventional assets primarily in the Gulf of Mexico which closed in third quarter 2018 and first quarter 2019.
(b)	Includes natural gas acquired for injection and subsequent resale.

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30		Mar. 31		June 30
	2019		2019		2018
United States - average price realizations (a)
Crude oil and condensate ($ per bbl) (b)	$	59.18	$	54.05	$	66.03
Eagle Ford	63.10		57.69		68.77
Bakken	56.84		52.15		64.41
Oklahoma	58.66		53.39		66.90
Northern Delaware	55.33		48.97		60.01
Other United States (c)	66.21		56.19		64.42
Natural gas liquids ($ per bbl)	$	14.60	$	15.66	$	22.09
Eagle Ford	13.19		17.05		22.68
Bakken	18.68		16.17		25.52
Oklahoma	14.39		13.66		20.75
Northern Delaware	15.02		15.27		19.10
Other United States (c)	17.25		18.92		25.62
Natural gas ($ per mcf) (d)	$	1.89	$	2.93	$	2.18
Eagle Ford	2.51		2.99		2.82
Bakken	1.70		3.77		2.46
Oklahoma	1.78		2.90		1.84
Northern Delaware	0.18		1.93		1.48
Other United States (c)	2.26		2.89		2.11
International - average price realizations
Crude oil and condensate ($ per bbl)	$	58.21	$	53.93	$	66.12
Equatorial Guinea	54.38		44.36		60.30
United Kingdom	68.40		67.62		77.15
Other International	55.83		47.76		64.73
Natural gas liquids ($ per bbl)	$	1.67	$	1.96	$	2.91
Equatorial Guinea (d)	1.00		1.00		0.99
United Kingdom	37.63		38.10		43.20
Natural gas ($ per mcf)	$	0.35	$	0.48	$	0.52
Equatorial Guinea (d)	0.24		0.24		0.24
United Kingdom	4.25		7.02		7.39
Benchmark
WTI crude oil (per bbl)	$	59.91	$	54.90	$	67.91
Brent (Europe) crude oil (per bbl) (e)	$	68.92	$	63.17	$	74.50
Henry Hub natural gas (per mmbtu) (f)	$	2.64	$	3.15	$	2.80


(a)	Excludes gains or losses on commodity derivative instruments.
(b)	Inclusion of realized gains (losses) on crude oil derivative instruments would have affected average price realizations by $0.32, $1.10 and $(7.04) for second quarter 2019, first quarter 2019, and second quarter 2018.
(c)	Includes sales volumes from the sale of certain non-core proved properties in our International and United States segments.
(d)	Represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and/or Equatorial Guinea LNG Holdings Limited, which are equity method investees. The Alba Plant LLC processes the NGLs and then sells secondary condensate, propane, and butane at market prices. Marathon Oil includes its share of income from each of these equity method investees in the International segment.
(e)	Average of monthly prices obtained from Energy Information Administration website.
(f)	Settlement date average per mmbtu.

Q3 2019 Production Guidance	Oil Production (mbbld)				Equivalent Production (mboed)
Q3 2019 Production Guidance	Q3 2019		Q2 2019	Q3 2018	Q3 2019		Q2 2019	Q3 2018
	Low	High	Divestiture-Adjusted (a)	Divestiture-Adjusted (a)	Low	High	Divestiture-Adjusted (a)	Divestiture-Adjusted (a)
Net production
United States	190	200	192	172	330	340	331	302
International	12	16	16	17	80	90	91	99
Total net production	202	216	208	189	410	430	422	401

Full Year 2019 Production Guidance	Oil Production (mbbld)			Equivalent Production (mboed)
Full Year 2019 Production Guidance	2019		2018	2019		2018
	Low (b)	High (b)	Divestiture-Adjusted (a)	Low (b)	High (b)	Divestiture-Adjusted (a)
Net production
United States	185	195	169	320	330	294
International	18	22	17	85	95	98
Total net production	203	217	186	405	425	392


(a)	Divestiture-adjusted, and also removes volumes associated with the sale of our U.K. business which closed on July 1, 2019.
(b)	Annual 2019 guidance includes 1H19 contributions from divested assets.

The following table sets forth outstanding derivative contracts as of August 5, 2019, and the weighted average prices for those contracts:

	2019					2020		2021
*Crude Oil*		Third Quarter		Fourth Quarter		Full Year		Full Year
*NYMEX WTI Three-Way Collars^(a)*
Volume (Bbls/day)		80,000		80,000		19,945		—
Weighted average price per Bbl:
Ceiling		$	74.19	$	74.19	$	67.55	—
Floor		$	56.75	$	56.75	$	55.00	—
Sold put		$	49.50	$	49.50	$	47.50	—
*Basis Swaps - Argus WTI Midland ^(b)*
Volume (Bbls/day)		15,000		15,000		15,000		—
Weighted average price per Bbl		$	(1.40)	$	(1.40)	$	(0.94)	—
*Basis Swaps - Net Energy Clearbrook ^(c)*
Volume (Bbls/day)		1,000		1,000		—		—
Weighted average price per Bbl		$	(3.50)	$	(3.50)	—		—
*Basis Swaps - NYMEX WTI / ICE Brent ^(d)*
Volume (Bbls/day)		5,000		5,000		5,000		808
Weighted average price per Bbl		$	(7.24)	$	(7.24)	$	(7.24)	$	(7.24)
*Basis Swaps - Argus WTI Houston ^(e)*
Volume (Bbls/day)		10,000		10,000		—		—
Weighted average price per Bbl		$	5.51	$	5.51	$	—	$	—
*NYMEX Roll Basis Swaps*
Volume (Bbls/day)		60,000		60,000		—		—
Weighted average price per Bbl		$	0.38	$	0.38	—		—


(a)	Between July 1, 2019 and August 5, 2019, we entered into 10,000 Bbls/day of three-way collars for January - December 2020, with a ceiling of $65.12, a sold put of $48.00, and a floor of $55.00.
(b)	The basis differential price is indexed against Argus WTI Midland.
(c)	The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook ("UHC").
(d)	The basis differential price is indexed against International Commodity Exchange ("ICE") Brent and NYMEX WTI.
(e)	The basis differential price is indexed against Argus WTI Houston.