10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-Q

[X]     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

OR

[  ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from _______ to _______      

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Oregon	93-0256722
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

220 N.W. Second Avenue, Portland, Oregon 97209

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code:  (503) 226-4211

 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes [ X ] No  [   ]

 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes [ X ]        No  [   ]

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ X ]	Accelerated filer [    ]
Non-accelerated filer [     ]	Smaller reporting company [    ]

 (Do not check if a smaller reporting company)

 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 

Yes [   ]       No  [ X ]

At April 30, 2011, 26,672,812 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended March 31, 2011

	PART I.  FINANCIAL INFORMATION
		Page Number
	Forward-Looking Statements	1
Item 1.	Consolidated Financial Statements:
	Consolidated Statements of Income for the three months ended March 31, 2011 and 2010	2
	Consolidated Balance Sheets at March 31, 2011 and 2010 and December 31, 2010	3
	Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	39
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6.	Exhibits	40
	Signature	41

Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995.  Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to statements regarding the following:

·   plans;

·   objectives;

·   goals;

·   strategies;

·   future events or performance;

·   trends;

·   cyclicality;

·   earnings and dividends;

·   growth;

·   customer rates;

·   commodity costs;

·   operational performance and costs;

·   liquidity and financial positions;

·   project development and expansion;

·   competition;

·   procurement and development of new gas supplies;

·   liquefied natural gas;

·   estimated expenditures;

·   costs of compliance;

·   credit exposures;

·   potential efficiencies;

·   impacts of laws, rules and regulations;

·   tax liabilities or refunds;

·   outcomes and effects of litigation, regulatory actions, and other administrative matters;

·   projected obligations under retirement plans;

·   adequacy of, and shift in mix of, gas supplies;

·   approval and adequacy of regulatory deferrals; and

·   environmental, regulatory, litigation and insurance costs and recoveries.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2010 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A “Risk Factors,” herein.

Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

1

NORTHWEST NATURAL GAS COMPANY

PART I.  FINANCIAL INFORMATION

Consolidated Statements of Income
(Unaudited)
	Three Months Ended
	March 31,
Thousands, except per share amounts	2011		2010
Operating revenues:
Gross operating revenues	$	323,088	$	286,529
Less: Cost of sales		180,625		148,561
Revenue taxes		7,955		7,042
Net operating revenues		134,508		130,926
Operating expenses:
Operations and maintenance		31,172		30,666
General taxes		8,165		3,249
Depreciation and amortization		17,309		15,901
Total operating expenses		56,646		49,816
Income from operations		77,862		81,110
Other income and expense - net		1,214		3,023
Interest expense - net		10,449		10,489
Income before income taxes		68,627		73,644
Income tax expense		27,854		30,036
Net income	$	40,773	$	43,608
Average common shares outstanding:
Basic		26,670		26,538
Diluted		26,724		26,601
Earnings per share of common stock:
Basic	$	1.53	$	1.64
Diluted	$	1.53	$	1.64
Dividends declared per share of common stock	$	0.435	$	0.415
See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I.  FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)
	March 31,			March 31,			December 31,
Thousands	2011			2010			2010
Assets:
Current assets:
Cash and cash equivalents	$	3,480		$	8,839		$	3,457
Restricted cash		924			40,924			924
Accounts receivable		94,521			78,347			67,969
Accrued unbilled revenue		42,342			39,244			64,803
Allowance for uncollectible accounts		(3,821	)		(3,999	)		(2,950	)
Regulatory assets		48,195			55,872			52,714
Derivative instruments		4,861			450			2,245
Inventories:
Gas		43,501			61,918			70,672
Materials and supplies		9,765			9,235			9,713
Income taxes receivable		23,645			-			41,066
Other current assets		13,292			15,481			19,652
Total current assets		280,705			306,311			330,265
Non-current assets:
Property, plant and equipment		2,593,553			2,409,534			2,576,402
Less: Accumulated depreciation		733,639			702,307			722,239
Total property, plant and equipment - net		1,859,914			1,707,227			1,854,163
Regulatory assets		345,452			331,962			348,897
Derivative instruments		1,560			5			628
Other investments		69,501			67,558			69,094
Other non-current assets		14,421			15,970			13,569
Total non-current assets		2,290,848			2,122,722			2,286,351
Total assets	$	2,571,553		$	2,429,033		$	2,616,616
See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I.  FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)
	March 31,			March 31,			December 31,
Thousands	2011			2010			2010
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,673, 26,564 and 26,668 at March 31, 2011 and 2010, and December 31, 2010, respectively	$	343,787		$	338,012		$	342,978
Retained earnings		385,899			361,310			356,727
Accumulated other comprehensive income (loss)		(6,458	)		(5,870	)		(6,604	)
Total common stock equity		723,228			693,452			693,101
Long-term debt		551,700			601,700			591,700
Total capitalization		1,274,928			1,295,152			1,284,801
Current liabilities:
Short-term debt		186,435			96,000			257,435
Current maturities of long-term debt		50,000			35,000			10,000
Accounts payable		71,839			93,534			93,243
Taxes accrued		10,063			27,325			10,579
Interest accrued		11,470			12,232			5,182
Regulatory liabilities		29,016			36,032			17,828
Derivative instruments		25,655			39,365			38,437
Other current liabilities		38,433			36,060			35,457
Total current liabilities		422,911			375,548			468,161
Deferred credits and other non-current liabilities:
Deferred tax liabilities		396,357			311,691			373,409
Regulatory liabilities		263,876			247,517			258,031
Pension and other postretirement benefit liabilities		132,053			118,848			144,250
Derivative instruments		13,914			18,637			17,022
Other non-current liabilities		67,514			61,640			70,942
Total deferred credits and other non-current liabilities		873,714			758,333			863,654
Commitments and contingencies (see Note 14)		-			-			-
Total capitalization and liabilities	$	2,571,553		$	2,429,033		$	2,616,616
See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I.  FINANCIAL INFORMATION

Consolidated Statement of Cash Flows
(Unaudited)
	Three Months Ended
	March 31,
Thousands	2011			2010
Operating activities:
Net income	$	40,773		$	43,608
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		17,309			15,901
Undistributed earnings from equity investments		25			(356	)
Non-cash expenses related to qualified defined benefit pension plans		1,817			2,001
Contributions to qualified defined benefit pension plans		(13,645	)		(10,000	)
Deferred environmental expenditures		(1,759	)		(3,632	)
Other		(443	)		(2,431	)
Changes in assets and liabilities:
Receivables		(3,122	)		31,951
Inventories		27,119			9,804
Taxes accrued		16,905			6,288
Accounts payable		(14,406	)		(24,882	)
Interest accrued		6,288			6,797
Deferred gas costs		196			(15,428	)
Deferred tax liabilities		25,048			11,517
Other - net		5,959			3,018
Cash provided by operating activities		108,064			74,156
Investing activities:
Capital expenditures		(25,403	)		(52,774	)
Restricted cash		-			(5,381	)
Other		(121	)		782
Cash used in investing activities		(25,524	)		(57,373	)
Financing activities:
Common stock issued (purchased) - net		(244	)		566
Change in short-term debt		(71,000	)		(6,000	)
Cash dividend payments on common stock		(11,601	)		(11,011	)
Other		328			69
Cash used in financing activities		(82,517	)		(16,376	)
Increase in cash and cash equivalents		23			407
Cash and cash equivalents - beginning of period		3,457			8,432
Cash and cash equivalents - end of period	$	3,480		$	8,839
Supplemental disclosure of cash flow information:
Interest paid	$	4,162		$	3,325
Income taxes paid	$	-		$	9,000
See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I.  FINANCIAL INFORMATION

 Notes to Consolidated Financial Statements

(Unaudited)

1. Organization and Principles of Consolidation

The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural) and all companies that we directly or indirectly control, either through majority ownership or otherwise.  Our direct and indirect wholly-owned subsidiaries include Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial).   Investments in corporate joint ventures and partnerships that we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method or the cost method, which includes NWN Energy’s investment in Palomar Gas Holdings, LLC (PGH).  NW Natural and its affiliated companies are collectively referred to herein as “NW Natural.”  The consolidated financial statements are presented after elimination of all significant intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation.  In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business and other non-utility investments and business activities (see Note 4).

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported.  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2010 Annual Report on Form 10-K (2010 Form 10-K).  A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Our significant accounting policies are described in Note 2 of the 2010 Form 10-K.  There were no material changes to those accounting policies during the three months ended March 31, 2011, except for a change in the application of our accounting policy with respect to revenue recognition for the regulatory adjustment for income taxes paid.  For further discussion of significant accounting policies, see Note 2 below.  Subsequent events are reported in Note 15.

Certain prior year balances in our consolidated financial statements have been combined or reclassified to conform with the current presentation.  These changes had no impact on our prior year’s consolidated results of operations and no material impact on financial condition or cash flows.

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2.           Summary of Significant Accounting Policies

Industry Regulation

At March 31, 2011 and 2010 and at December 31, 2010, the amounts deferred as regulatory assets and liabilities were as follows:

	Regulatory Assets
	March 31,		March 31,		December 31,
Thousands	2011		2010		2010
Current:
Unrealized loss on derivatives(1)	$	25,655	$	39,365	$	38,437
Pension and other postretirement benefit liabilities(2)		10,988		7,502		10,988
Other(3)		11,552		9,005		3,289
Total current	$	48,195	$	55,872	$	52,714
Non-current:
Unrealized loss on derivatives(1)	$	13,914	$	18,637	$	17,022
Income tax asset		70,241		75,515		72,341
Pension and other postretirement benefit liabilities(2)		115,490		108,010		118,248
Environmental costs(4)		117,544		107,537		114,311
Other(3)		28,263		22,263		26,975
Total non-current	$	345,452	$	331,962	$	348,897
	Regulatory Liabilities
	March 31,		March 31,		December 31,
Thousands		2011		2010		2010
Current:
Gas costs payable	$	14,144	$	26,164	$	15,583
Unrealized gain on derivatives(1)		4,861		450		2,245
Other(3)		10,011		9,418		-
Total current	$	29,016	$	36,032	$	17,828
Non-current:
Gas costs payable	$	3,932	$	2,377	$	2,297
Unrealized gain on derivatives(1)		1,560		5		628
Accrued asset removal costs		256,203		242,952		252,941
Other(3)		2,181		2,183		2,165
Total non-current	$	263,876	$	247,517	$	258,031

(1)   An unrealized gain or loss on derivatives does not earn a rate of return or a carrying charge.  These amounts, when realized at settlement, are recoverable through utility rates as part of the Purchased Gas Adjustment mechanism.

(2)   Certain pension and other postretirement benefit liabilities of the utility are approved for regulatory deferral.  Such amounts are recoverable in rates, including an interest component, when recognized in pension expense or net periodic benefit cost (see Note 9).

(3)   Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms.  The accounts being amortized typically earn a rate of return or carrying charge.

(4)   Environmental costs are related to certain utility sites that are approved for regulatory deferral.  We earn the utility’s authorized rate of return as a carrying charge on amounts paid, whereas the amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended.

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Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers.  Since 2007, utility revenues have also included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon.  Under SB 408, we are required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount is based on the estimated difference between income taxes paid and income taxes authorized to be collected in customer rates. We have recorded the estimated refund, or surcharge, each quarter since 2007 based on the estimated annual amount to be recognized. However, on March 29, 2011, a legislative bill was introduced that would repeal SB 408 if enacted as drafted in its current form (SB 967 or Bill). As of May 4, 2011, the Oregon Senate had approved SB 967, but the Bill has not been approved by the Oregon House of Representatives or signed by the Governor of Oregon. We currently believe there is substantial uncertainty surrounding the continuation of the current legal requirements of SB 408.  Accordingly, we determined that the threshold for recognizing revenues under the accounting standard for the effects of regulation had not been met, and therefore we did not record an estimated refund, or surcharge, in the first quarter of 2011 for this regulatory adjustment for income taxes paid.

New Accounting Standards

Adopted Standards

Fair Value Disclosures. In January 2010, the Financial Accounting Standards Board issued authoritative guidance on new fair value measurements and disclosures.  This guidance requires additional disclosures for fair value measurements that use significant assumptions not observable in active markets (i.e. level 3 valuations), including a rollforward schedule.  These changes were effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note 9 in our 2010 Form 10-K.  The adoption of this standard did not have a material effect on our financial statement disclosures.

Recent Accounting Pronouncements

There have been no recent accounting pronouncements issued, but not yet effective, which are expected to have a material impact on our financial condition, results of operations or cash flows.

3. Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented.  Diluted earnings per share are computed using the weighted average number of common shares outstanding plus the potential effects of the assumed exercise of stock options, and payment of estimated stock awards from other stock-based compensation plans that are outstanding, at the end of each period presented.  Diluted earnings per share are calculated as follows:

	Three Months Ended
	March 31,
Thousands, except per share amounts	2011		2010
Net income	$	40,773	$	43,608
Average common shares outstanding - basic		26,670		26,538
Additional shares for stock-based compensation plans		54		63
Average common shares outstanding - diluted		26,724		26,601
Earnings per share of common stock - basic	$	1.53	$	1.64
Earnings per share of common stock - diluted	$	1.53	$	1.64

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For the three months ended March 31, 2011 and 2010, 2,150 and 5,120 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares on the net income for both periods would have been anti-dilutive.

4. Segment Information

We operate in two primary reportable business segments, local gas distribution and gas storage.  We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.”  We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our “gas storage” segment includes NWN Gas Storage, a wholly-owned subsidiary of NWN Energy, Gill Ranch, a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of our Mist underground storage facility in Oregon (Mist) and third-party optimization services. Our “other” segment includes NNG Financial and our equity investment in PGH which is pursuing development of the Palomar pipeline project.  For further discussion of our segments, see Note 4 in our 2010 Form 10-K.

The following table presents summary financial information about the reportable segments for the three months ended March 31, 2011, and 2010.  Inter-segment transactions were insignificant.

	Three Months Ended March 31
			Non-Utility
Thousands	Utility		Gas Storage		Other			Total
2011
Net operating revenues	$	129,162	$	5,304	$	42		$	134,508
Depreciation and amortization		15,914		1,395		-			17,309
Income from operations		76,124		1,716		22			77,862
Net income (loss)		40,130		688		(45	)		40,773
Total assets at March 31, 2011		2,304,731		244,403		22,419			2,571,553
2010
Net operating revenues	$	125,473	$	5,411	$	42		$	130,926
Depreciation and amortization		15,566		335		-			15,901
Income from operations		76,582		4,511		17			81,110
Net income		40,892		2,501		215			43,608
Total assets at March 31, 2010		2,190,849		217,266		20,918			2,429,033
Total assets at December 31, 2010	$	2,310,388	$	282,945	$	23,283		$	2,616,616

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5. Common Stock

As of March 31, 2011, our common shares authorized were 100,000,000 and our outstanding shares were  26,672,812.

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions.  We currently have Board authorization through May 2011 to repurchase up to an aggregate of 2.8 million shares, or up to $100 million. No shares of common stock were repurchased pursuant to this program during the three months ended March 31, 2011, but since inception in 2000 a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.

6. Stock-Based Compensation

We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan.  These plans are designed to promote stock ownership in NW Natural by employees and officers.  For additional information on our stock-based compensation plans, see Part II, Item 8., Note 6, in the 2010 Form 10-K and current updates provided below.

Long-Term Incentive Plan.  On February 23, 2011, 37,950 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of $25.25 per share.  Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

Stock price on valuation date	$	45.74
Performance term (in years)		3.0
Quarterly dividends paid per share	$	0.435
Expected dividend yield		3.7	%
Dividend discount factor		0.8930

In February 2011, the Board approved a payout of performance-based stock awards under the LTIP for the 2008-10 award period.  Shares of common stock were purchased on the open market to satisfy these awards.

Restated Stock Option Plan.  On February 23, 2011, options to purchase 122,700 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $45.74 per share on the date of grant, vesting over a four-year period following the date of grant and with a term of 10 years and 7 days. The weighted-average grant date fair value was $6.73 per share.  Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:

Risk-free interest rate	2.0	%
Expected life (in years)	4.5
Expected market price volatility factor	24.5	%
Expected dividend yield	3.8	%
Forfeiture rate	3.1	%

As of March 31, 2011, there was $1.3 million of unrecognized compensation cost related to the unvested portion of outstanding Restated SOP awards expected to be recognized over a period extending through 2014.  

7. Cost and Fair Value Basis of Long-Term Debt

Cost of Long-Term Debt

Our long-term debt consists of medium-term notes (MTNs) with maturity dates from 2011 through 2035, interest rates ranging from 3.95 percent to 9.05 percent, and a weighted-average coupon rate of 6.17 percent.  For the three months ended March 31, 2011, we did not issue or redeem any MTNs.  For more detail on our outstanding long-term debt, see Note 7 in our 2010 Form 10-K.

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Fair Value of Long-Term Debt

The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date.  Because our debt outstanding does not trade in active markets, we used interest rates for other company’s outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value of our long-term debt issues.  These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

	March 31,				December 31,
Thousands	2011		2010		2010
Carrying amount	$	601,700	$	636,700	$	601,700
Estimated fair value	$	680,436	$	687,937	$	690,126

8. Comprehensive Income

Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax.  The amount of accumulated other comprehensive loss in stockholders’ equity is $6.5 million and $5.9 million as of March 31, 2011 and 2010, respectively, which is related to employee benefit plan liabilities.  The following table provides a reconciliation of net income to total comprehensive income for the three months ended March 31, 2011 and 2010.

	Three Months Ended
	March 31,
Thousands	2011		2010
Net income	$	40,773	$	43,608
Amortization of employee benefit plan liability, net of tax		146		98
Total comprehensive income	$	40,919	$	43,706

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9. Pension and Other Postretirement Benefit Costs

The following tables provide the components of net periodic benefit cost for our company-sponsored qualified and non-qualified defined benefit pension plans and other postretirement benefit plans:

	Three Months Ended March 31,
							Other Postretirement
	Pension Benefits						Benefits
Thousands	2011			2010			2011			2010
Service cost	$	1,899		$	1,773		$	168		$	156
Interest cost		4,527			4,491			344			343
Expected return on plan assets		(4,456	)		(4,564	)		-			-
Amortization of net actuarial loss		2,692			1,768			68			7
Amortization of prior service costs		88			206			49			49
Amortization of transition obligations		-			-			103			103
Net periodic benefit cost		4,750			3,674			732			658
Amount allocated to construction		(1,235	)		(953	)		(226	)		(208	)
Net amount charged to expense	$	3,515		$	2,721		$	506		$	450

See Part II, Item 8., Note 9, in the 2010 Form 10-K for more information about our pension and other postretirement benefit plans.

In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement, known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan).  The cost of this plan is in addition to pension expense in the table above.  The Western States Plan has reported an accumulated funding deficit for the current plan year and remains in critical status.  The Western States Plan trustees adopted a rehabilitation plan that reduced benefit accrual rates and adjustable benefits for active employee participants and increased future employer contribution rates.  These changes are expected to improve the funding status of the plan.  We made contributions totaling $0.1 million to the Western States Plan for both the three months ended March 31, 2011 and 2010.  If we withdraw and the plan is underfunded, we could be assessed a withdrawal liability.  Currently, we have no intent to withdraw from the plan, so we have not recorded a withdrawal liability.

Employer Pension Contributions

During the first quarter of 2011 we made cash contributions totaling $13.6 million to our qualified defined benefit pension plans.  We also expect to contribute up to an additional $10 million to these qualified plans over the last nine months of 2011, plus we expect to make ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 9, in the 2010 Form 10-K.

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10.           Income Tax

The effective income tax rate for the three months ended March 31, 2011 and 2010 varied from the combined federal and state statutory tax rates principally due to the following:

	March 31,
	2011			2010
Federal statutory tax rate		35.0	%		35.0	%
Increase (decrease):
Current state income tax, net of federal tax benefit		4.6	%		4.9	%
Amortization of investment and energy tax credits		-0.4	%		-0.5	%
Differences required to be flowed-through by regulatory commissions		1.5	%		1.5	%
Gains on company and trust-owned life insurance		-0.2	%		-0.2	%
Other - net		0.1	%		0.1	%
Effective income tax rate		40.6	%		40.8	%

The decrease in our effective tax rate for the three months ended March 31, 2011 compared to the same period in 2010 was minor and primarily due to a change in state income tax rates. See Note 10 in our 2010 Form 10-K.

11. Property, Plant and Equipment

The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation as of March 31, 2011 and 2010 and December 31, 2010:

	March 31,				December 31,
Thousands	2011		2010		2010
Utility plant in service	$	2,264,055	$	2,206,571	$	2,247,952
Utility construction work in progress		28,464		25,736		29,324
Less: Accumulated depreciation		720,134		691,420		710,214
Utility plant-net		1,572,385		1,540,887		1,567,062
Non-utility plant in service		292,089		66,084		290,038
Non-utility construction work in progress		8,945		111,143		9,088
Less: Accumulated depreciation		13,505		10,887		12,025
Non-utility plant-net	$	287,529	$	166,340	$	287,101
Total property, plant and equipment	$	1,859,914	$	1,707,227	$	1,854,163

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12.           Investments

Our other long-term investments include financial investments in life insurance policies, which are accounted for at fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods.  See Part II, Item 8., Note 12, in the 2010 Form 10-K for more detail on our investments.

Variable Interest Entities.PGH is a development stage variable interest entity.  Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system.  PGH is owned 50 percent by NWN Energy and 50 percent by Gas Transmission Northwest Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation.  As of March 31, 2011, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations.  Therefore, we account for our investment in PGH and the Palomar project under the equity method, which is included in other investments on our balance sheet.  Our maximum loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50 percent owner.

PGH Impairment Analysis.In March 2011, Palomar withdrew its original application with the Federal Energy Regulatory Commission (FERC) for a proposed natural gas pipeline in Oregon.  At the same time, Palomar informed FERC that it intends to file an application later this year or in 2012 to reflect changes in the project and more closely align with the region’s current and future gas needs. Palomar is working with customers in the Northwest to further understand their gas transportation needs.  Assuming Palomar obtains commercial support for its revised pipeline proposal, Palomar expects to file a new certificate application with FERC.

We performed an impairment analysis of our equity investment as of March 31, 2011 and determined that we did not have any impairment because the fair value of expected cash flows from development of this pipeline project exceeds our equity investment. If, however, we learn that the project is not viable or will not go forward, then we could be required to recognize an impairment charge of up to approximately $14.4 million based on the amount of our equity investment of $14.8 million as of March 31, 2011 net of cash and working capital at Palomar.  We will continue to monitor and update our impairment analysis as needed.

13. Derivative Instruments

We enter into swap, option and various option combinations for the purpose of hedging natural gas.  We primarily use these derivative financial instruments to manage commodity prices related to our natural gas purchase requirements.  A small portion of the derivatives are also related to foreign currency exchange transactions.

In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers.  We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to the physical gas supply contracts.  Derivatives entered into prudently for future gas years prior to our annual PGA filing receive regulatory deferred accounting treatment.  Derivative contracts entered into after the annual PGA rate was set on November 1, 2010 that are for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for a 90 percent deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10 percent recognized on the income statement.

Most of our commodity hedging for the upcoming gas year is completed prior to the start of each gas year, and these hedge prices are included in our annual PGA filing.  We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather.  We entered the 2010-11 gas year (November 1, 2010 – October 31, 2011) hedged at a level of approximately 77 percent, including 62 percent financially hedged and 15 percent physically hedged with gas in storage.  

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At March 31, 2011, we were hedged with financial contracts for the upcoming 2011-12 gas year at approximately 50 percent based on anticipated sales volumes.  Of the amount currently hedged for the 2011-12 gas year approximately 35 percent was hedged with financial contracts and an additional 15 percent attributable to storage from future purchases and current storage levels.

The following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments for the years ended March 31, 2011 and 2010.  All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to the balance sheet accounts in accordance with regulatory accounting.

		Three Months Ended
		March 31, 2011							March 31, 2010
Thousands			Natural gas commodity(1)			Foreign currency (2)				Natural gas commodity(1)			Foreign currency (2)
Cost of sales			$	(33,750	)	$	-			$	(57,564	)	$	-
Other comprehensive income (loss)				-			602				-			(17	)
Less:
Amounts deferred to regulatory accounts on balance sheet				33,750			(602	)			57,564			17
	Total impact on earnings		$	-		$	-			$	-		$	-
(1)	Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet.
(2)	Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

We had no collateral posted with our counterparties as of March 31, 2011 or 2010.  We attempt to minimize the potential exposure to collateral calls by our counterparties to manage our liquidity risk.  Based on our current credit ratings, most counterparties allow us credit limits ranging from $25 million to $50 million before collateral postings are required.  Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We also could be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change.  Based upon current contracts outstanding, which reflect unrealized losses of $33.1 million at March 31, 2011, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:

			Credit Rating Downgrade Scenarios
Thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	-	$	-	$	-	$	3,223	$	18,058
Without Adequate Assurance Calls	$	-	$	-	$	-	$	3,223	$	14,897

In the three months ended March 31, 2011 and 2010, we realized net losses of $20.9 million and $6.2 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of gas.  The exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.

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We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of our customers.  For more information on our derivative instruments, see Note 13 in our 2010 Form 10-K.

Fair Value

In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments.  This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position.  Our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at March 31, 2011.  As of March 31, 2011 and 2010 and December 31, 2010, the fair value was $33.1 million, $57.5 million and $52.6 million, respectively, using significant other observable, or level 2, inputs.  We have used no level 3 inputs in our derivative valuations.  We also did not have any transfers between level 1 or level 2 during the three months ended March 31, 2011 and 2010.

14. Commitments and Contingencies

Environmental Matters

We own, or previously owned, properties that may require environmental remediation or action.  We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable.  We continue to study and evaluate the extent of our potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases we have disclosed the nature of the potential loss and the fact that the high end of the range cannot be reasonably estimated.

We regularly review our environmental liability for each site where we may be exposed to remediation responsibilities.  The costs of environmental remediation are difficult to estimate.  A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure.  Each of these steps may, over time, involve a number of alternative actions, each of which can change the course and scope of the effort.  Many of these steps are dependent upon the approval and direction of federal and state environmental regulators.  The policies, determinations and directions of the regulators may develop and change over time and different regulators may take different positions on the various steps, creating further uncertainty as to the timing and scope of remediation activities.  In certain cases, in addition to us, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course and scope of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be highly uncertain.  The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties.  Site investigations and remediation efforts often develop slowly over many years.  In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular environmental matters and what remediation efforts are appropriate.  These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

We estimate the range of loss for environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties.  Unless there is an estimate within this range of possible losses that is more likely than other cost estimates, we record the liability at the lower end of this range.  It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives.  The status of each of the sites currently under investigation is provided below.

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Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Remediation Investigation Report and submitted it to the ODEQ for review.  We also submitted a Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which ODEQ conditionally approved in March 2008, subject to the submission of additional information.  We provided that information to ODEQ and are now working with the agency on the final design for the source control system.  Based on the information  currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.8 million at March 31, 2011.  The range of liability will be reassessed when ODEQ makes a final source control design decision.  In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires the design of remedial action for sediments from the Gasco site. This design project is underway. We also have other investigation and clean-up work, including work on the uplands portion of the Gasco site, that we expect to be required. For the sediments project and other work, we have recorded an additional accrued liability of $38.0 million, which reflects the low end of the range of potential liability.  We have accrued at the low end of the range of potential liability for the sediments project and other environmental work at the Gasco site because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Siltronic site.We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ.  The liability accrued at March 31, 2011 for the Siltronic site is $1 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), completion of which is scheduled for 2011. The EPA and the Lower Willamette Group are conducting focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA.  In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims.  As of March 31, 2011, we have a liability accrued of $8 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway.  As of March 31, 2011, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies. The EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority.  Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies were completed.  In 2010, ODEQ required additional studies which are underway.  As of March 31, 2011, we have an estimated liability accrued of $0.9 million for the study of the sediments and riverbank groundwater and soils at the site.  The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Oregon Steel Mills site. See “Legal Proceedings,” below.

Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at March 31, 2011 and 2010 and December 31 2010:

	Current Liabilities						Non-Current Liabilities
	Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,
Thousands	2011		2010		2010		2011		2010		2010
Gasco site	$	13,718	$	9,924	$	11,366	$	36,099	$	42,165	$	38,921
Siltronic site		730		679		720		291		508		201
Portland Harbor site		2,219		1,873		2,304		5,829		7,041		5,784
Central Service Center site		5		5		5		501		511		510
Front Street site		-		72		1		947		252		1,097
Other sites		-		-		-		117		106		108
Total	$	16,672	$	12,553	$	14,396	$	43,784	$	50,583	$	46,621

Regulatory and Insurance Recovery for Environmental Costs.  In May 2003, the Public Utility Commission of Oregon (OPUC) approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above.  Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and interest accrual was extended through January 2010.  We have filed a request with the OPUC to extend this deferral, and expect authorization during the second quarter of 2011.  In addition, we filed a request with the Washington Utilities and Transportation Commission (WUTC) in February 2011 to defer certain environmental costs associated with services provided to Washington customers, and expect an order from the WUTC during the second quarter of 2011.

On a cumulative basis, we have recognized a total of $106.3 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and paid prior to regulatory deferral order approval.  At March 31, 2011, we had a regulatory asset of $117.5 million, which includes $47.1 million of total paid expenditures to date, $60.5 million for additional environmental costs expected to be paid in the future and accrued interest of $15.3 million, partially offset by $5.4 million of environmental costs expensed in prior years.  See table below.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US Insurance Company, certain underwriters at Lloyd's London, certain London market insurance companies and ten other insurance companies.  In the suit, NW Natural alleges that the defendant insurance companies issued third party liability insurance policies to NW Natural and that the defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities arising from environmental contamination at certain sites caused or alleged to be caused by its historical operations.  NW Natural seeks damages in excess of $40 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.  After seeking recovery of our environmental costs from our insurers, we believe recovery of the remainder of our deferred charges, if any, is probable through the regulatory process. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We continue to anticipate that our overall insurance recovery effort will extend over several years.

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We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated within the next 12 months because we do not expect to have concluded our insurance recovery efforts during that time period, and because recovery would be expected to occur through the implementation of new rates through a general rate proceeding. As such we have classified our regulatory assets for environmental cost deferrals as non-current.  The following table summarizes the non-current regulatory assets relating to environmental sites at March 31, 2011 and 2010 and December 31, 2010:

	Non-Current Regulatory Assets
	March 31,		March 31,		December 31,
Thousands	2011		2010		2010
Gasco site	$	76,338	$	70,411	$	74,205
Siltronic site		3,440		3,020		3,174
Portland Harbor site		34,732		32,140		33,940
Central Service Center site		558		550		553
Front Street site		2,042		1,032		2,020
Other sites		434		384		420
Total	$	117,544	$	107,537	$	114,312

Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows.

Oregon Steel Mills site.In 2004, NW Natural was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial and discovery is ongoing. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

15.           Subsequent Event

On April 28, 2011 the OPUC issued an order approving our investment to develop gas reserves on behalf of our Oregon customers under an agreement with Encana Oil & Gas (USA) Inc.  Under the agreement, we expect to invest approximately $45-55 million a year, over a five-year period, for a total investment of about $250 million, which will cover a portion of drilling costs in exchange for working interests in certain sections of the Jonah Field located north of Rock Springs, Wyoming.  These sections include both future and current producing wells.  The gas reserves will provide long-term gas supplies for our Oregon utility customers over a period expected to be about 30 years.  During the first 10 years of the agreement, we forecast to receive approximately 58 billion cubic feet (Bcf) from the transaction, or 8-10 percent of our average annual requirements for utility operations.  Our total investment under the agreement is expected to result in about 93 Bcf of gas at an average all-in price of approximately $5.15 per dekatherm.  We estimate net present value savings to customers of over $50 million over the life of the investment as compared to other long-term supply alternatives.

Under the order, the OPUC determined that the investment was prudent and that the Company is allowed to recover its costs under the agreement on an ongoing basis through its Purchased Gas Adjustment (PGA) cost sharing mechanism, including the deferral process for the commodity cost of gas.  Annually, the Company will forecast amounts related to the costs and volumes expected, and variances will be subject to the PGA’s normal sharing mechanism up to $10 million of variance.  Any variance in excess of $10 million, either negative or positive, will be passed through to customers at 100 percent, rather than at the 80 or 90 percent level associated with the normal sharing mechanism.  As part of the decision by the OPUC to approve the Company’s investment, we will file a general rate case in Oregon no later than December 31, 2011.

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the three months ended March 31, 2011 and 2010. Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated Financial Statements in this report. This discussion should be read in conjunction with our 2010 Annual Report on Form 10-K (2010 Form 10-K).

The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned subsidiaries which include: Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial).  These statements also include accounts related to an equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). Together these accounts make up our regulated local gas distribution business, our gas storage businesses, and other regulated and non-regulated investments primarily engaged in energy-related businesses. In this report, the term “utility” is used to describe our regulated gas distribution business (local distribution company), and the term “non-utility” is used to describe our gas storage businesses (gas storage) as well as our other regulated and non-regulated investments and business activities (other).  For a further discussion of our business segments, see Note 4.

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our 2010 Form 10-K).  

Executive Summary

Highlights of the first quarter of 2011 as compared to the same period in 2010 include:

·   Consolidated earnings of $40.8 million or $1.53 per share in the first quarter of 2011, as compared to $43.6 million and $1.64 in the first quarter of 2010;

·   Net income from utility operations decreased $0.8 million, from $40.9 million in 2010 to $40.1 million in 2011, largely due to benefits received last year from a property tax refund and the regulatory adjustment for income taxes paid (see Revenue Recognition below under Application of Critical Accounting Policies and Estimates for further discussion of the regulatory adjustment for income taxes paid);

·   Net income from gas storage operations decreased $1.8 million, from $2.5 million in 2010 to $0.7 million in 2011, primarily reflecting Gill Ranch’s initial start-up costs and lower level of contracted capacity prior to its first injection season beginning April 1, 2011;

·   Consolidated net operating revenues (margin) increased $3.6 million or 3 percent over 2010, with utility margin up $3.7 million and gas storage margin down $0.1 million;

·   Consolidated total operating expenses increased $6.8 million or 14 percent over 2010, but that was largely attributed to a $5.2 million refund of property tax expense at the utility in 2010 and start-up costs at Gill Ranch;

·   Other income decreased $1.8 million in 2011 compared to 2010, primarily due to $1.9 million of interest income received by the utility in 2010 in connection with the property tax refund referred to above;

·   Cash flow from operating activities in 2011 was $108.0 million, for an increase of $33.9 million or 46 percent over 2010; and

·   The utility added more than 6,000 new customers over the last 12 months, for an annual growth rate of 0.9 percent compared to 0.7 percent a year ago.

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Issues, Challenges and Performance Measures

Economic Environment.  Weakness in the local, national and global economies has continued to adversely impact utility customer growth, the demand for natural gas, and the value of natural gas storage services.  Most recently, our utility’s annual customer growth rate increased slightly to 0.9 percent at March 31, 2011, as compared to 0.7 percent at March 31, 2010.  Although total delivered volumes to utility customers in the first quarter of 2011 increased 20 percent, we are still faced with unemployment rates around 10 percent in our service territories of Oregon and southwest Washington and a sluggish business environment.  Despite these challenges, we believe we are well positioned to continue adding utility customers due to lower natural gas prices, a relatively low market penetration rate, our ongoing efforts to convert homes to natural gas, and the potential for environmental initiatives that could favor natural gas use in our region.

Managing Gas Prices and Supplies.Our gas acquisition strategy is regularly updated to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so that we can effectively manage costs, reduce price volatility and maintain a competitive advantage.  With recent developments in drilling technologies and substantial access to supplies from shale gas formations around the U.S. and in Canada, the supply outlook for North American natural gas has increased dramatically, which is contributing to lower and more stable gas prices.  We entered the 2010-11 gas contract year, which began November 1, 2010, with gas commodity prices hedged at approximately 77 percent of our forecasted purchase volumes.  In addition, we are currently hedged at approximately 50 percent for the 2011-12 gas contract year and between 5 and 10 percent for the 2012-13 gas contract year.  The Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our own gas price hedging strategies and gas supplies in storage, enable us to reduce earnings risk exposure for the company and secure lower gas costs for our customers.  These lower gas prices, coupled with quality service and energy saving programs for customers, can help strengthen natural gas’ competitive price advantage compared to other fuels.  See discussion of Utility Investment in Gas Reserves below under Strategic Opportunities.

Although stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage business by lowering the value of, and reducing the demand for, storage services thus limiting Gill Ranch’s ability to sign customer contracts for longer terms at favorable prices.

Environmental Costs.We accrue all material environmental loss contingencies related to our properties that require environmental investigation or remediation.  Due to numerous uncertainties surrounding the preliminary nature of investigations or the developing nature of remediation requirements, actual costs could vary significantly from our loss estimates.  As a regulated utility, we are allowed to defer certain costs pursuant to regulatory decisions.  In 2010 and prior years, we were authorized by the Public Utility Commission of Oregon (OPUC) to defer certain environmental costs, and to seek recovery of those amounts in future rates to customers. For 2011, we have a request pending before the OPUC to approve an extension of the deferral order for certain environmental costs.  However, before we can seek recovery from customers, we are expected to pursue recovery from insurance policies.  Ultimate recovery of environmental costs, either from regulated utility rates or from insurance, will depend on our ability to effectively manage these costs and demonstrate they were prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory assets, and amounts not recovered would be required to be charged to income in the period they were deemed to be unrecoverable.  See Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 14 in this report and Note 15 in our 2010 Form 10-K.

Climate change. See Part II, Item 7., “Executive Summary - Issues, Challenges and Performance Measures—Climate change,” in our 2010 Form 10-K for a discussion of the effect of climate change on our business.

Performance Measures. In order to deal with the challenges affecting our businesses, we annually review and update our strategic plan to map our course over the next several years.  Our plan includes strategies for: further improving our utility gas distribution services and operations; growing our non-utility gas storage business; investing in new natural gas infrastructure in the region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support clean energy technologies.  We intend to measure our performance and monitor progress on certain metrics including, but not limited to: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction ratings; utility margin; utility capital and operations and maintenance expense per customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility EBITDA).

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Strategic Opportunities

Business Process Improvements.To address the current economic and competitive challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to develop, integrate, consolidate and streamline operations and support our employees with new technology tools.

Gas Storage Operations.  Gill Ranch began operations during the fourth quarter of 2010.  Gill Ranch is offering storage services to the California market at market-based rates, subject to California Public Utilities Commission (CPUC) regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances.  Due to increasing supplies and price stability of natural gas in North America, and declining demand for natural gas due to current economic conditions, storage values are expected to remain low in the near term, which will likely affect the prices at which Gill Ranch is able to contract. For more information, see Note 4 in this report and Part II, Item 7., “2011 Outlook—Strategic Opportunities,” in our 2010 Form 10-K.

The Pacific Northwest storage markets also are negatively impacted by lower gas prices and lack of gas price volatility, but less so than in California and many other markets around the country because of limited availability of storage capacity.  In 2011, we expect to continue planning for possible expansion at our gas storage facilities near Mist, Oregon in anticipation of increased demand for electric generation in the Pacific Northwest.  Currently we do not have a set timeline for the next expansion at Mist, but we believe the earliest timeframe for completion would be no earlier than 2013 or 2014.  In the meantime, we will continue to monitor the market demand and work on preliminary design and project planning, which will ultimately require the development of storage wells, potentially a second compression station and additional pipeline gathering facilities that will enable future storage expansions.

Pipeline Diversification. Currently, our utility and Mist gas storage operations depend on a single bi-directional interstate transmission pipeline to ship gas supplies.  Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system.  PGH is owned 50 percent by NWN Energy and 50 percent by Gas Transmission Northwest Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation.  The Palomar pipeline was originally proposed with an east and a west segment, but Palomar currently plans to design an east only pipeline to serve our utility customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed pipeline would be regulated by the Federal Energy Regulatory Commission (FERC).  

In March 2011, Palomar withdrew its original application with FERC for a natural gas pipeline in Oregon, but at the same time Palomar informed FERC that it intends to file a new application later this year or in 2012, after it has conducted an open season and obtained commercial support for the eastern portion of the pipeline between Madras and Molalla in Oregon.

Utility Investment in Gas Reserves. In addition to hedging gas prices with financial derivative contracts over the next few years, we recently signed an agreement with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves that are expected to supply a portion of our utility customers’ requirements over a period of about 30-years.  During the first 10 years of the agreement, we forecast the volumes of gas received under the agreement to provide approximately 8 to 10 percent of the average annual requirements of our utility customers.  Under the agreement, we expect to invest approximately $45 million to $55 million a year for five-years, with our total investment estimated to be about $250 million.

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On April 28, 2011, the OPUC issued an order finding this gas reserve investment prudent and approving it for utility ratemaking, which provides for the recovery of the costs plus a rate base return on our investment through the annual Purchased Gas Adjustment (PGA) mechanism, including the deferral process for the commodity cost of gas.  Annually, we will forecast the amounts related to costs and volumes expected, and variances between forecasted and actual will be subject to the PGA incentive sharing provision in Oregon, up to a maximum variance of $10 million (for a discussion of the incentive sharing provision, see “Results of Operations – Regulatory Matters – Rate Mechanisms” below).  Any variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent.  As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Consolidated Earnings and Dividends

The most significant factors contributing to the $2.8 million decrease in consolidated net income as compared to the prior year were:

·   a $6.1 million decrease related to a refund of property taxes in 2010, which is reflected by an operating expense increase of $5.2 million under general taxes and a $1.0 million decrease under operations and maintenance, plus an interest income decrease of $1.9 million under other income;

·   a $2.7 million decrease related to a change in our revenue recognition policy for the regulatory adjustment of income taxes paid in 2011 as compared to 2010 (see “Application of Critical Accounting Policies and Estimates – Revenue Recognition,” and “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below); and

·   a $1.8 million decrease in net income from our gas storage segment, primarily reflecting Gill Ranch’s low level of contracted capacity prior to its first injection season beginning April 1, 2011  coupled with initial start-up costs.

Partially offsetting the above factors were:

·   a $6.4 million increase in utility net operating revenue (margin) attributable to an increase in residential and commercial customer use, which reflect gains from colder weather and customer growth, an increase in industrial use, and an increase in our incentive share of gas cost savings; and

·   a $2.2 million decrease in income tax expense due to lower taxable income.

Dividends paid on our common stock were 43.5 cents per share in the first quarter of 2011, compared to 41.5 cents per share in the first quarter of 2010.  The Board of Directors declared a quarterly dividend on our common stock of 43.5 cents per share, payable on May 13, 2011, to shareholders of record on April 29, 2011.  The current indicated annual dividend rate is $1.74 per share.

Application of Critical Accounting Policies and Estimates

    In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements.  Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions.  Our most critical estimates and judgments include accounting for:

·   regulatory cost recovery and amortizations;

·   revenue recognition;

·   derivative instruments and hedging activities;

·   pensions and postretirement benefits;

·   income taxes; and

·   environmental contingencies.

There have been no material changes to the information provided in the 2010 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2010 Form 10-K), except as indicated below under Revenue Recognition.  

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Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers.  Since 2007, utility revenues have also included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon.  Under SB 408, we are required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount is based on the estimated difference between income taxes paid and income taxes authorized to be collected in customer rates. We have recorded the estimated refund, or surcharge, each quarter since 2007 based on the estimated annual amount to be recognized. However, on March 29, 2011, a legislative bill was introduced that would repeal SB 408 if enacted as drafted in its current form (SB 967 or Bill). As of May 4, 2011, the Oregon Senate had approved SB 967, but the Bill has not been approved by the Oregon House of Representatives or signed by the Governor of Oregon. We currently believe there is substantial uncertainty surrounding the continuation of the current legal requirements of SB 408.  Accordingly, we determined that the threshold for recognizing revenues under the accounting standard for the effects of regulation had not been met, and therefore we did not record an estimated refund, or surcharge, in the first quarter of 2011 for this regulatory adjustment for income taxes paid.  See “Results of Operations—Business Segments - Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for a further discussion of regulatory asset amounts included on the balance sheet as of March 31, 2011 related to the prior year.

Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.  Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported, except for the item discussed above under Revenue Recognition.  For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 2.

Results of Operations

Regulatory Matters

Regulation and Rates

We are subject to regulation with respect to, among other matters, rates and systems of accounts by the OPUC), Washington Utilities and Transportation Commission (WUTC), FERC, and with respect to Gill Ranch, the CPUC.  The OPUC and WUTC and, with respect to Gill Ranch, the CPUC, also regulate our issuance of securities.  In 2011, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers and the balance from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington economies in general, by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, operating and maintenance costs and investments made in utility plant.  See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2010 Form 10-K.

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Rate Mechanisms

Purchased Gas Adjustment.  Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases, including contract gas purchase prices, gas prices hedged with financial derivatives, gas inventory prices, interstate pipeline demand costs, the application of temporary rate adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the previous year.

In October 2010, the OPUC and WUTC approved PGA rate changes effective on November 1, 2010.  The effect of these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by 2 percent.  This is our second consecutive year of rate decreases.

     Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select by August 1 of each year either an 80 percent deferral or a 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively.  In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings review to determine if the utility is earning above its allowed ROE threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that level are required to be deferred for refund to customers.  Under this provision, if we select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE.  If we select the 90 percent deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90 percent deferral option for both the 2009-2010 and the 2010-2011 PGA years.   The ROE threshold is subject to adjustment annually based on movements in long-term interest rates.  In 2010 and 2009, the ROE threshold after adjustment for long-term interest rates was 11.02 percent and 11.5 percent, respectively.  No amounts were required to be refunded to customers as a result of the 2009 utility earnings review.  Based upon utility results for 2010 and the first quarter of 2011 we accrued approximately $0.5 million and $1.0 million, respectively, for refund to customers in future rates

There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual gas costs and pass that difference through to customers as an adjustment to future rates.  We do not have an earnings or gas cost sharing mechanism in Washington.

Regulatory Recovery for Environmental Costs.  The OPUC has authorized us to defer environmental costs associated with certain named sites and to accrue interest on environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses.  We have filed a request for an extension of this deferral and expect to receive this authorization during the second quarter of 2011.  See Note 14.  In February 2011, we filed a request with the WUTC to defer environmental costs associated with services provided to Washington customers.  We expect an order from the WUTC within the following few months.

Pension Deferral.  Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower pension expenses in future years.  Our recovery of deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return.  The estimated reduction to operations and maintenance expense for 2011 is estimated to be in the range of $4 to $5 million, and $1.3 million was deferred in the first quarter of 2011.  Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities using a number of key assumptions, as well as our pension contributions.

For a discussion of other rate mechanisms, see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2010 Form 10-K.

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Business Segments - Utility Operations

Our utility margin results are largely affected by customer growth and to a certain extent by changes in weather and customers’ gas usage patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers.  In Oregon, we have a conservation tariff that adjusts margin revenues to offset changes resulting from increases or decreases in residential and commercial customers’ gas usage.  We also have a weather normalization mechanism in Oregon that adjusts customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter heating season.  Both mechanisms are designed to reduce the volatility of our utility earnings and customer charges.

Our utility segment in the first quarter of 2011 earned $40.1 million, or $1.50 per share, compared to $40.9 million, or $1.54 per share for the same period in 2010. The major factors contributing to the change in earnings were higher margins from residential and commercial customers, which were up $6.2 million largely due to the impact of colder weather, along with higher industrial customer margins, which were up $0.5 million, partially offset by increased operating expenses.  Total volumes sold and delivered in the first quarter of 2011 increased 20 percent over last year, with residential and commercial volumes up 29 percent on weather that was 21 percent colder than last year, plus a 5 percent increase in industrial volumes over last year.  Operating expenses were higher in the first quarter of 2011 primarily due to a refund of property taxes recognized in the first quarter of 2010 (see General Taxes, below).

Our weather normalization mechanism adjusted residential and commercial margins down by $5.9 million for the first quarter of 2011 based on temperatures that were 6 percent colder than average, compared to a margin increase of $13.5 million for the first quarter of 2010 when temperatures were 13 percent warmer than average.  Our decoupling mechanism adjusted residential and commercial margins up by $8.7 million in 2011, compared to a margin increase of $7.9 million in 2010.

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The following table summarizes the composition of gas utility volumes, revenues and margin:

		Three Months Ended						Favorable/
		March 31,						(Unfavorable)
Thousands, except degree day and customer data		2011			2010			2011 vs. 2010
Utility volumes - therms:
Residential sales			174,930			133,860			41,070
Commercial sales			99,967			78,856			21,111
Industrial - firm sales			10,637			10,153			484
Industrial - firm transportation			35,690			32,611			3,079
Industrial - interruptible sales			17,239			16,324			915
Industrial - interruptible transportation			62,951			61,599			1,352
	Total utility volumes sold and delivered		401,414			333,403			68,011
Utility operating revenues - dollars:
Residential sales		$	198,774		$	169,609		$	29,165
Commercial sales			95,313			80,075			15,238
Industrial - firm sales			8,956			8,618			338
Industrial - firm transportation			1,591			1,436			155
Industrial - interruptible sales			10,483			10,381			102
Industrial - interruptible transportation			2,310			1,919			391
Regulatory adjustment for income taxes paid(1)			286			2,984			(2,698	)
Other revenues			14			6,041			(6,027	)
	Total utility operating revenues		317,727			281,063			36,664
Cost of gas sold			180,610			148,548			(32,062	)
Revenue taxes			7,955			7,042			(913	)
	Utility margin	$	129,162		$	125,473		$	3,689
Utility margin:(2)
Residential sales		$	84,252		$	66,404		$	17,848
Commercial sales			32,558			25,708			6,850
Industrial - sales and transportation			7,610			7,123			487
Miscellaneous revenues			1,584			1,673			(89	)
Gain (loss) from gas cost incentive sharing			1,035			199			836
Other margin adjustments			(1,027	)		(19	)		(1,008	)
	Margin before regulatory adjustments		126,012			101,088			24,924
Weather normalization adjustment			(5,861	)		13,535			(19,396	)
Decoupling adjustment			8,725			7,866			859
Regulatory adjustment for income taxes paid(1)			286			2,984			(2,698	)
	Utility margin	$	129,162		$	125,473		$	3,689
Customers - end of period:
Residential customers			612,738			606,935			5,803
Commercial customers			62,800			62,477			323
Industrial customers			908			917			(9	)
	Total number of customers - end of period		676,446			670,329			6,117
Actual degree days			1,974			1,627
Percent colder (warmer) than average weather(3)			6	%		(13	) %
(1)	Regulatory adjustment for income taxes paid is described below.
(2)	Amounts reported as margin for each category of customers are net of cost of gas sold and revenue taxes.
(3)	Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.

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Residential and Commercial Sales

The primary factors that impact results of operations in the residential and commercial markets are customer growth, seasonal weather patterns, energy prices, competition from other energy sources and economic conditions in our service areas.  Typically, 80 percent or more of our utility’s operating revenues on an annual basis are derived from gas sales to weather-sensitive residential and commercial customers.  Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced by our weather normalization mechanism in Oregon where about 90 percent of our customers are served.  For more information on our weather mechanism, see Regulatory Matters—Rate Mechanisms—Weather Normalization in our 2010 Form 10-K.

The primary changes that impacted margin from residential and commercial sales for the three months ended March 31, 2011 compared to March 31, 2010 were as follows:

·   utility sales volumes were 29 percent higher, primarily reflecting 21 percent colder weather;

·   utility operating revenues increased $44.4 million or 18 percent primarily due to 29 percent increased volumes, partially offset by lower average use per customer due to conservation efforts; and

·   utility margin increased $6.2 million or 5 percent reflecting increased volumes from residential and commercial customer growth of 0.9 percent and colder weather, which was partially offset by weather normalization adjustments that benefit customer bills when weather is colder than normal. 

Industrial Sales and Transportation

Operating revenues from industrial customers include the commodity cost component of gas sold under sales service but not under transportation service. Therefore, operating revenues from industrial customers can increase or decrease when customers switch between sales service and transportation service, but generally our margins from these customers are unaffected by these changes because we do not include a profit mark-up for the cost of gas. As such, we believe volumes delivered and margins are better measures of performance for the industrial sector. The primary changes that impacted volumes and margins from industrial sales and transportation services for the three months ended March 31, 2011 compared to March 31, 2010 were as follows:

·   volumes delivered to industrial customers increased 5.8 million therms, or 5 percent, due to a slight increase in energy demand. The majority of the increased volumes were attributable to the manufacturing sector; and

·   margin from industrial customers increased $0.5 million, or 7 percent primarily due to the increase in total volumes delivered.

Regulatory Adjustment for Income Taxes Paid

Oregon law currently requires certain regulated natural gas and electric utilities to annually review the amount of income taxes collected in rates from utility operation and compare it to the amount the utility actually pays to taxing authorities.  Under this law, if we pay less in income taxes related to utility operations than we collect from Oregon utility customers, then we are required to refund the excess to our Oregon utility customers.  Conversely, if we pay more in income taxes than we collect from Oregon utility customers, then we are required to collect a surcharge from Oregon utility customers.

For the 2009 tax year, the OPUC approved our tax filing to recover $5.6 million, including interest, through a surcharge to Oregon utility customers.  It was agreed that the 2009 surcharge, plus accrued interest, would be collected over a one-year period beginning June 1, 2011.  For the 2010 tax year, we estimated the difference between income taxes paid and the amounts collected in rates will result in a surcharge of $7.1 million, excluding interest.  The 2010 surcharge was primarily driven by a refund of property taxes as well as by utility operating margins including gains from gas cost savings related to our PGA incentive sharing.

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For the three months ended March 31, 2011, we estimate the surcharge to be $2.7 million for the regulatory adjustment of income taxes paid. However, we did not recognize revenues in this period for the regulatory adjustment due to the uncertainty surrounding our ability to collect the expected 2011 surcharge in future rates. For further discussion, see “Revenue Recognition” above under Application of Critical Accounting Policies and Estimates. However, we did recognize revenues of $0.3 million in the three months ended March 31, 2011 for accrued interest attributed to surcharges related to the 2009 and 2010 tax years, as compared to $3.0 million for the same period in 2010, which included a surcharge of $2.9 million plus accrued interest of $0.1 million attributed to the 2008 and 2009 tax years.

On March 29, 2011, legislation was introduced in Oregon (SB 967) to repeal existing statutes governing the annual regulatory adjustment for income taxes paid.  This legislative bill would repeal the regulatory adjustment for tax years after 2009 upon the effective date.  In order to ensure a proper balance between income taxes collected in rates by regulated natural gas and electric utilities and amounts actually paid to taxing authorities, SB 967 would require the OPUC to make decisions in future ratemaking proceedings on the amounts of income taxes to be recovered in rates. As of May 4, 2011, SB 967 had been approved by the Oregon Senate but not by the Oregon House of Representatives.  If the Oregon legislature votes to pass SB 967 in its current form and the bill is signed into law by the governor, then the asset amounts on the balance sheet at March 31, 2011 for the 2010 tax year, which totals $7.4 million including accrued interest would be impaired and need to be written-off.  Such an impairment would result in an after-tax adjustment of approximately $4.4 million, which is equivalent to 17 cents per share.

Other Revenues

Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts, except for gas cost deferrals which flow through cost of gas sold.  Other revenues decreased from $6.0 million for the three months ended March 31, 2010 to less than $0.1 million for the three months ended March 31, 2011, primarily reflecting a $2.1 million decrease in the decoupling amortization, a $1.0 million accrual for estimated refunds to utility customers related to our earnings sharing mechanism, a $1.4 million decrease for the warm deferral related to colder weather, and a $1.3 million decrease in other regulatory amortizations.

Cost of Gas Sold

Cost of gas sold includes gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.  Our regulated utility does not generally earn a profit, or incur a loss, on gas commodity purchases.  The OPUC and WUTC require natural gas commodity costs to be billed to customers at the same cost incurred, or expected to be incurred, by the utility.  However, under the PGA mechanism in Oregon, our net income can be affected by differences between actual and expected gas costs, which occur primarily because of market fluctuations and volatility affecting unhedged gas purchases (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above).  We use natural gas commodity-based hedge contracts (derivatives), primarily fixed-price commodity swaps, consistent with our financial derivatives policies to help manage our exposure to rising gas prices.  Gains and losses from these financial hedge contracts are generally included in our PGA prices and normally do not impact net income because the hedged prices are usually 100 percent passed through to customers in annual rate changes, subject to a regulatory prudency review. However, utility hedge contracts entered into after the annual PGA rates are set in Oregon can impact net income because we would be required to share in any gains or losses compared to the corresponding commodity prices built into rates in the PGA. In Washington, cost of gas sold does not affect our margins or net income because 100 percent of the actual gas costs, including hedge gains and losses allocated to Washington gas sales, are passed through in customer rates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2010 Form 10-K, and Note 13 in this report). The following summarizes the major factors that contributed to changes in cost of gas sold for the three months ended March 31, 2011:

·   total cost of gas sold increased $32.1 million, or 22 percent, due to a 20 percent increase in total sales volumes and a 2 percent decrease in the average cost of gas sold per therm;

·   the average gas cost collected through rates decreased from 61 cents per therm in 2010 to 60 cents per therm in

·   2011, primarily reflecting lower gas prices that were passed on through PGA rate decreases effective November 1, 2009 and 2010; and

·   hedge losses totaling $20.9 million were realized and included in cost of gas sold for the three months ended March 31, 2011, compared to $6.2 million of hedge losses in the same period of 2010. Since the underlying hedge prices were included in our PGA billing rates, these losses did not impact margin or net income.

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The amount recorded to pre-tax income from the shareholders’ portion of  our gas cost incentive sharing mechanism was a margin contribution of $1.0 million in the first quarter of 2011 compared to $0.2 million in 2010.  For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.

Business Segments - Gas Storage

Our gas storage segment primarily consists of the acquisition, development, operation and management of natural gas storage facilities.  As of March 31, 2011, we owned and operated non-utility investments at our Mist underground storage facility in Oregon and at our Gill Ranch underground storage facility in California. Construction of the Gill Ranch storage facility was completed and placed into service during the fourth quarter of 2010. Our gas storage segment also includes asset optimization services using unused gas storage and transportation capacity. For the three months ended March 31, 2011, our gas storage segment earned $0.7 million, or 3 cents per share, compared to $2.5 million, or 9 cents per share, for the same period in 2010.  This decrease was primarily related to net losses at Gill Ranch due to initial start-up costs and low storage contract revenues prior to April 1, 2011, which is the start of Gill Ranch’s first injection season, and partly due to a slight downturn in revenues from firm storage and optimization services at Mist.

Gas storage net operating revenues (margin) decreased $0.1 million to $5.3 million for the three months ended March 31, 2011.  This decrease in margin is primarily due to a decrease in Mist third-party optimization revenues of $0.8 million, partially offset by Gill Ranch’s revenues of $0.6 million.

Business Segments - Other

Our other business segment consists primarily of NNG Financial’s investment in KB Pipeline, our investment in PGH which in turn has invested in the Palomar pipeline project, and our other non-utility investments and business activities.  NNG Financial had total assets of $1.1 million and $1.2 million as of March 31, 2011 and 2010, respectively, primarily reflecting a non-controlling minority interest in the Kelso-Beaver pipeline.  Our net equity investment in PGH as of March 31, 2011 and 2010 was $14.8 million and $14.5 million, respectively.  Earnings from our other business segment as of March 31, 2011 and 2010 was a net loss of less than $0.1 million and net income of $0.2 million, respectively. See Note 4 in the 2010 Form 10-K and in this report.

Consolidated Operations

Operations and Maintenance

Consolidated operations and maintenance expense was $31.2 million in 2011, compared to $30.7 million in 2010, a increase of $0.5 million or 2 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense for the three months ended March 31, 2011 compared to March 31, 2010:

·   a $1.1 million increase for operating expenses at Gill Ranch, including $0.8 million for  labor related expenses and $0.3 for compressor related expenses; and

·   a $0.6 million increase in accrued performance bonuses at the utility based on above-target year-to-date operating results compared to last year.

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Partially offsetting the above factors were:

·   a $1.0 million decrease in consulting and legal fees due to prior year costs related to our successful property tax appeal;

·   a $0.2 million decrease in utility bad debt expense (see below for further discussion); and

·   a $0.2 million decrease in pension expense due to the effects of the new regulatory deferral of pension expense authorized by the OPUC (see below for further discussion).

Our bad debt expense as a percent of revenues was 0.18 percent for the twelve months ended March 31, 2011, compared to 0.33 percent for the same period last year. The decrease in our bad debt expense ratio was partly due to improved collections and recoveries of delinquent account balances. Despite these improvements, we believe credit risks are still elevated due to the weak economy and high unemployment rates. Higher customer usage from colder weather these past few months may increase our exposure to credit losses over the remainder of this year.  

Effective January 1, 2011, the OPUC approved the deferral of utility pension costs related to NW Natural’s qualified defined benefit plans for operations and maintenance expense above the amount recovered in rates, which was set in our last general rate case. The pension expense deferral is recorded to a regulatory balancing account, which we expect to result in an estimated $4 to $5 million cumulative amount for 2011.  So far, we have deferred $1.3 million of pension expense in the first quarter of 2011, which, when netted with pension expense, resulted in a $0.2 million decrease to operations and maintenance expense compared to the same period in 2010.  For further explanation of the pension balancing account, see “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.

General Taxes

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased $4.9 million in the first three months of 2011 compared to 2010.  The major factor that contributed to the change in general taxes was a prior year $5.2 million refund of property taxes pursuant to a favorable ruling from the Oregon Supreme Court (see below for further discussion).

For several years, we had been involved in litigation with the Oregon Department of Revenue over the taxability of certain inventories that were held for sale, including gas inventories.   In January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these inventories were exempt from property tax.  As a result of this ruling, we were refunded $5.2 million, plus accrued interest, for taxes paid on inventories beginning with the 2002-03 tax year.  We recognized a net $6.1 million increase in pre-tax income in the first quarter of 2010, which consisted of $5.2 million for the refund of property taxes, $1.9 million for accrued interest income, and $1.0 million of increased operations and maintenance expense for legal and consulting fees.

Depreciation and Amortization

Total depreciation and amortization expense in 2011 increased by $1.4 million, or 9 percent, as compared to the same period in 2010.  The increased expense in 2011 was primarily related to Gill Ranch depreciation, which relates to assets that went into service in the fourth quarter of 2010.  A portion of the increase was also related to additional investments in utility plant related to customer growth and system improvements.

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Other Income and Expense – Net

     The following table provides details on other income and expense – net by primary components:

	Three Months Ended
	March 31,
Thousands	2011			2010
Gains from company-owned life insurance	$	505		$	396
Interest income		7			1,910
Income from equity investments		-			316
Net interest on deferred regulatory accounts		1,514			991
Gain (loss) on sale of investments		(96	)		223
Other non-operating		(716	)		(813	)
Total other income and expense - net	$	1,214		$	3,023

Other income and expense – net decreased $1.8 million, primarily due to the prior year’s refund of property taxes as discussed above, which included $1.9 million in accrued interest income. Other income and expense also included a $0.5 million increase in interest from regulatory account balances largely due to smaller gas costs refund balances, which was partially offset by our share of reduced income from an equity investment.

Interest Expense – Net

Interest expense—net of amounts capitalized in 2011 decreased by less than $0.1 million compared to 2010.  The decrease is due to a $0.4 million savings from interest expense on long term debt as a result of bonds that matured in 2010, partially offset by a $0.2 million increase for gas storage related to the Gill Ranch base gas lease.

Income Tax Expense

The decrease in income tax expense of $2.2 million or 7 percent, compared to 2010 was primarily due to lower pre-tax consolidated earnings of $5.0 million or 7 percent and a decrease in our effective tax rate of 40.6 percent in 2011 compared to 40.8 percent in 2010.

For the 2011 tax year, the lower effective tax rate was primarily the result of a decrease in the Oregon statutory income tax rate from 7.9 percent for tax year 2010 to 7.6 percent for tax year 2011.  For the 2010 tax year, the higher effective tax rate was primarily the result of increased amortization of our regulatory tax account on pre-1981 utility plant assets (see “Regulatory Matters—Rate Mechanisms,” above) and a lower non-taxable gain on company-owned life insurance. For more information on our income taxes, including a reconciliation between the statutory federal and state income tax rates and the effective rate, see Note 10.

In July 2009, the governor of Oregon signed House Bill 3405 establishing increases in the state income tax rate for corporations, and Oregon voters approved this legislation in January 2010.  The corporate income tax rate in Oregon increased from 6.6 percent to 7.9 percent for tax years 2009 and 2010 when taxable income is greater than $250,000.  For tax years 2011 and 2012, the income tax rate will decrease to 7.6 percent, and for years after 2012 the tax rate will return to 6.6 percent, except for corporations with taxable income over $10 million the tax rate will remain at 7.6 percent.

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Financial Condition

Capital Structure

One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt.  If additional capital is required, then debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources of capital are also used to fund long-term debt redemptions and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Note 7).  Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs.  Our consolidated capital structure at March 31, 2011 and 2010 and at December 31, 2010 was as follows:

	March 31,						December 31,
	2011			2010			2010
Common stock equity		47.9	%		48.6	%		44.7	%
Long-term debt		36.5	%		42.2	%		38.1	%
Short-term debt, including current maturities of long-term debt		15.6	%		9.2	%		17.2	%
Total		100	%		100	%		100	%

Liquidity and Capital Resources

At March 31, 2011, we had $3.5 million of cash and cash equivalents compared to $8.8 million at March 31, 2010. We also had $0.9 million in restricted cash invested at Gill Ranch as of March 31, 2011, compared to $40.9 million at March 31, 2010, which was being held as collateral for equipment purchase contracts and construction loans.  In order to maintain sufficient liquidity during periods of volatile capital markets, at times we will maintain higher cash balances, add short-term borrowing capacity, and pre-fund utility capital expenditures while long-term fixed rate environments are attractive.  Our short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, committed multi-year credit facilities, cash available from surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt.  We use long-term debt proceeds generally to finance utility capital expenditures, refinance maturing short-term and long-term debt and provide for general corporate purposes.

With our current debt ratings (see “Credit Ratings,” below), we have been able to issue commercial paper and medium term notes (MTNs) at attractive rates and have not needed to borrow from our back-up credit facilities. In the event that we were not able to issue new debt due to market conditions, we expect that our near term liquidity needs could be met by using cash balances or drawing upon our committed credit facilities. We also have a universal shelf registration filed with the Securities and Exchange Commission for the issuance of secured and unsecured debt or equity securities, subject to market conditions and regulatory approvals.  We have OPUC approval to issue up to $175 million of additional MTNs under the existing shelf registration, which was filed in January 2011.

In the event that our senior unsecured long-term debt credit ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit or other form of collateral, which could expose us to additional cash requirements and may trigger significant increases in short-term borrowings.  If the credit risk-related contingent features underlying these contracts were triggered on March 31, 2011, we could have been required to post $18.1 million of collateral to our counterparties, but that assumes our long-term debt ratings were at non-investment grade levels (see Note 13 and “Credit Ratings,” below), which is several rating levels below our current ratings.

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Business developments that could have a material impact on our liquidity and capital resource position include pension contributions, tax benefits and environmental expenditures and insurance recoveries.  With respect to pension requirements, we expect to make additional contributions in 2011 and future years until we are fully funded under the Pension Protection Act rules (see “Pension Cost and Funding Status of Qualified Retirement Plans,” below).  With respect to federal income tax liabilities, an extension was granted that allows us to take 50 percent bonus depreciation on a majority of our capital expenditures in 2010, and 100 percent bonus depreciation on qualified expenditures during 2011, which significantly reduces our tax liability for the 2010 and 2011 tax years, thereby providing cash flow benefits in 2011 (see “Cash Flows—Operating Activities,” below).  With respect to environmental liabilities, we expect to continue using cash resources to fund our environmental liabilities, but we also anticipate recovering amounts through insurance coverage or utility rates over the next several years, although the amount and timing of these expenditures and recoveries is uncertain (see Note 14).

In addition, Gill Ranch began commercial operations in the fourth quarter of 2010.  Although we anticipate future operating cash flows at Gill Ranch to increase as the facility grows to its full design capacity by the end of 2013 and as we contract for incremental storage capacity.  The amount and timing of cash flows will depend on future storage values and our ability to optimize storage capacity.

In July 2010, the U.S. Congress passed and President Obama signed into law the “Wall Street Reform and Consumer Protection Act.” The new legislation requires additional government regulation of derivative and over-the-counter transactions, and could expand collateral requirements.  While we are currently evaluating the new legislation to determine its impact, if any, on our hedging procedures, results of operations, financial position and liquidity, we do not expect to know the full impact of the legislation until final regulations implementing the legislation are issued.

Based on several factors, including our current credit ratings, recent experience issuing commercial paper, current cash reserves, committed credit facilities and other liquidity resources, and our expected ability to issue long-term debt in the form of an MTN program under our universal shelf registration, we believe our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations and investing and financing activities discussed below.

Off-Balance Sheet Arrangements

Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material off-balance sheet financing arrangements.

Contractual Obligations

At March 31, 2011, our purchase commitments increased approximately $28 million since December 31, 2010, primarily involving contracts entered into in the normal course of business (see “Financial Condition—Contractual Obligations,” in the 2010 Form 10-K).

Short-Term Debt

Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial paper.  In addition to issuing commercial paper to meet working capital requirements, including seasonal requirements to finance gas inventories and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements.  Commercial paper is periodically refinanced through the sale of long-term debt or equity securities.  Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities (see “Credit Agreements,” below).  Our commercial paper program did not experience any liquidity disruptions as a result of the credit problems that affected issuers of asset-backed commercial paper and certain other commercial paper programs over the last several years.  At March 31, 2011 and 2010, our utility had commercial paper outstanding of $186.4 million and $56.0 million, respectively.  The effective interest rate on the utility’s commercial paper outstanding at March 31, 2011 and 2010 was 0.4 percent and 0.3 percent, respectively.

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In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million, which was extended through September 30, 2010.  In June 2010, Gill Ranch repaid its $40 million bank loan.  The effective interest rate on the Gill Ranch credit facility was 0.8 percent during 2010.

Credit Agreements

We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250 million, which may be extended for additional one-year periods subject to lender approval.  All lenders agreed to extend the original term for an additional one-year period through May 31, 2013.   We also had three bilateral credit agreements totaling $50 million in effect from November 30, 2010 through March 31, 2011. All lenders under our syndicated and bilateral credit agreements are major financial institutions with committed balances and investment grade credit ratings as of March 31, 2011 as follows:

		Loan Commitment Amounts in Thousands
		Syndicated		Bilateral
Lender rating, by category		Facility		Facility
AAA/Aaa		$	-	$	-
AA/Aa			230,000		50,000
A/A			20,000		-
BBB/Baa			-		-
	Total	$	250,000	$	50,000

Based on credit market conditions, it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency.  However, based on our current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default swap spreads and credit ratings, we believe the risk of lender default is minimal.

As discussed above, we extended commitments with all seven lenders under the syndicated agreement, with commitments totaling $250 million.  The syndicated agreement also allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the maturity date of the credit agreement. The syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment.

Any principal and unpaid interest amounts owed on borrowings under the credit agreements are due and payable on or before the maturity date. There were no outstanding balances under these credit agreements at March 31, 2011 and 2010.  These agreements also require us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at March 31, 2011 and 2010, with consolidated indebtedness to total capitalization ratios of 52 percent and 51 percent, respectively.

The syndicated and bilateral agreements also require that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies.  A change in our debt ratings by S&P or by Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. However, a change in our debt rating below BBB- or Baa3 would require additional approval from the OPUC prior to issuance of debt, and interest rates on any loans outstanding under the credit agreements are tied to debt ratings, which would increase or decrease the cost of any loans under the credit agreements when ratings are changed (see “Credit Ratings,” below).

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All three lenders under the short-term credit agreements are existing lenders under our syndicated credit agreement. The short-term credit agreements require us to comply with the terms and conditions of the syndicated credit agreement and give the lenders under the short-term credit agreements the same rights with respect to the short-term credit agreements that they have under the syndicated credit agreement.  The bilateral credit agreement expired March 31, 2011.

Credit Ratings

Our debt credit ratings are a factor in our liquidity, affecting our access to the capital markets including the commercial paper market.  Our debt credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts.  A change in our ratings below BBB- by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to our issuing additional long-term debt.

The following table summarizes our current debt ratings from S&P and Moody’s:

	S&P	Moody’s
Commercial paper (short-term debt)	A-1	P-1
Senior secured (long-term debt)	A+	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time.  The disclosure of these credit ratings is not a recommendation to buy, sell or hold NW Natural securities.  Each rating should be evaluated independently of any other rating.

Maturity and Redemption of Long-Term Debt

For the three months ended March 31, 2011 and 2010 there were no long-term debt maturities or redemptions.  Over the next twelve months, $10 million of secured MTNs, with a coupon rate of 6.665%, mature in June 2011, and another $40 million of secured MTNs, with a coupon rate of 7.13%, mature in March 2012.  For additional long-term debt maturing over the next five years, see Part II, Item 7., "Results of Operations—Financial Condition—Contractual Obligations," in our 2010 Form 10-K.

Cash Flows

Operating Activities

Three months ended March 31, 2011 compared to March 31, 2010:

Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results.  For the year ended March 31, 2011, cash flow from operating activities totaled $108.1 million compared to $74.2 million in 2010.  The significant factors contributing to changes in operating cash flow in the first three months of 2011 compared to 2010 are as follows:

·   a decrease of $35.1 million from changes in receivables primarily due to higher balances from colder weather at the end of 2009, which benefitted cash flows during 2010;

·   an increase of $17.3 million from changes in inventories primarily due the decreases in gas prices and increases in gas inventory withdrawals from storage in 2011 compared to 2010;

·   an increase of $15.6 million from changes in the deferred gas cost regulatory account balance, which reflects a lower variance between actual gas prices and embedded gas prices in the PGA for 2011 compared to 2010;

·   an increase of $13.5 million from deferred income taxes, primarily reflecting higher tax benefits from bonus

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·   depreciation taken from Gill Ranch capital investments placed in service;

·   an increase of $10.6 million from income taxes receivable and accrued taxes, primarily related to our federal refund received in the first quarter of 2011 of $14.4 million; and

·   an increase of $10.5 million from changes in gas costs payable due to weather impact on gas purchases.

In September 2010, Congress passed the Unemployment Insurance, Reauthorization and Job Creation Act of 2010 (the Act) and the legislation was signed into law by President Obama.  The Act extends for one additional year the temporary bonus depreciation rules first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009.  Under the bonus depreciation provision, an additional first-year tax deduction was allowed for depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010, and 100 percent through December 31, 2011, in the year the property is placed in service, and the remaining percentage recovered under the normal depreciation rules.  The 50 percent or 100 percent depreciation deduction in the first year is an acceleration of depreciation deductions that otherwise would be taken in the later years of an asset’s recovery period.  As a result of this extension, we will recognize an increase in our cash flow by reducing our current tax liabilities for the 2011 tax year.  Any deductions in excess of 2011 income tax liabilities for federal income tax purposes will be carried forward to the 2012 tax year.  As of March 31, 2011, we have a federal and state income tax receivable balance of $23.6 million, which we expect to realize in cash flows during 2011.  We received a federal refund of approximately $14.4 million during the first quarter of 2011.

For the year ended December 31, 2010, we reported an estimated net operating loss (NOL) for federal income tax purposes of $94.4 million, primarily due to the effects of accelerated tax depreciation provided by the 2010 Act.  The federal NOL will be carried back to 2009 and partially utilized for a refund of taxes paid in prior years.  The remaining NOL of approximately $20.2 million will be carried forward to reduce current taxes paid in the 2011 tax year.  We anticipate that we will be able to use all loss carry-forwards in future years.  The 2010 federal NOL would expire in 2031 if not used in earlier years.

Investing Activities

Cash used in investing activities for the three months ended March 31, 2011 totaled $25.5 million, down from $57.4 million for the same period in 2010.  Capital expenditures were $25.4 million in the three months ended March 31, 2011, down from $52.8 million for the same period in 2010, of which $27.0 million of the decrease was due to non-utility construction activity primarily related to Gill Ranch.  

In 2011, capital expenditures are estimated to be between $95 million and $105 million for the utility, excluding our proposed investment in long-term gas reserves (for further discussion, see Note 15). For non-utility development projects, we expect to spend between $5 million and $15 million total in 2011 for capital projects currently in process (see “Strategic Opportunities,” above).  Over the next five-year period 2011 through 2015, total utility capital expenditures are estimated at between $400 and $500 million, excluding the investment of approximately $250 million in gas reserves.  The estimated level of utility capital expenditures over the next five years reflects assumptions for customer growth, storage facility improvements, technology investments and utility distribution improvements, including requirements under the current Pipeline Safety programs.  Most of the required funds are expected to be internally generated over the five-year period, except for the funding of long-term gas reserves.  Any remaining funding that is needed to meet capital requirements will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing liquidity and bridge financing.

In 2011, Palomar expects to continue working on revised plans for the east pipeline segment and to conduct an open season to determine regional needs. The initial planning and permitting costs have been financed with equity funds from us and our partner, GTN.  For more information, see Note 12 and “Strategic Opportunities—Pipeline Diversification,” above.

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Financing Activities

Cash used in financing activities during the three months ended March 31, 2011 totaled $82.5 million, up from cash used of $16.4 million for the same period in 2010.  Our short-term debt balances decreased $71.0 million in the three months ended March 31, 2011, compared to a decrease of $6.0 million for the same period in 2010.  We continue to use long-term debt proceeds to finance capital expenditures, refinance maturing short-term or long-term debt maturities, and for general corporate purposes.

Pension Cost and Funding Status of Qualified Retirement Plans

We make pension contributions to company-sponsored qualified defined benefit plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our qualified defined benefit plans were underfunded by $95.4 million at December 31, 2010.  During the first quarter of 2011, we contributed $13.6 million into these plans.  We anticipate making additional contributions of between $8 million and $10 million before year end.  In 2010, we contributed a total of $10 million, and in 2009 we contributed a total of $25 million.  For more information on the funded status of our qualified retirement plans and other postretirement benefits, see Note 9, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 9, “Pension and Other Postretirement Benefits,” in the 2010 Form 10-K.

We also contribute to a multi-employer pension plan (Western States Plan) pursuant to our collective bargaining agreement.  We made contributions totaling $0.1 million to the Western States Plan in both the three months ended March 31, 2011 and 2010, and we expect to contribute a total of $0.4 million during 2011. 

Ratios of Earnings to Fixed Charges

For the three and twelve months ended March 31, 2011 and the twelve months ended December 31, 2010, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were  7.37,  3.63 and  3.73 respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income.  See Exhibit 12.

Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in our 2010 Form 10-K).  At March 31, 2011, we had a regulatory asset of $117.5 million for deferred environmental costs, which includes $60.5 million for additional costs expected to be paid in the future and accrued interest of $15.3 million.  If it is determined that both the insurance recovery and future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made.  For further discussion of contingent liabilities, see Note 14.

ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk and weather risk.  We monitor and manage these financial exposures as an integral part of our overall risk management program.  No material changes have occurred related to our disclosures about market risk this quarter.  See Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the 2010 Form 10-K for details regarding these risks.

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ITEM 4.     CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The Company's management, together with its consolidated subsidiaries, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)).  Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

The Company's management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f).

There have been no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II.  OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 14 and those proceedings disclosed and incorporated by reference in Part I, Item 3., “Legal Proceedings,” in our 2010 Form 10-K, we have only routine nonmaterial litigation in the ordinary course of business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, “Item 1A. Risk Factors,” in our 2010 Form 10-K.  In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations. The risks described in the 2010 Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our financial condition, results of operations or cash flows.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table provides information about purchases by us during the quarter ended March 31, 2011 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASE OF EQUITY SECURITIES

					(c)		(d)
	(a)		(b)		Total Number of Shares		Maximum Dollar Value of
	Total Number		Average		Purchased as Part of		Shares that May Yet Be
	of Shares		Price Paid		Publicly Announced		Purchased Under the
Period	Purchased(1)		per Share		Plans or Programs(2)		Plans or Programs(2)
Balance forward						2,124,528	$	16,732,648
01/01/11 - 01/31/11		1,232	$	45.81		-		-
02/01/11 - 02/28/11		21,417		45.76		-		-
03/01/11 - 03/31/11		11,006		47.16		-		-
Total		33,655	$	46.22		2,124,528	$	16,732,648

  (1)  During the quarter ended March 31, 2011, 23,503 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 10,152 shares of our common stock were purchased on the open market during the quarter to meet the requirements of our share-based programs.  During the quarter ended March 31, 2011, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

  (2)  We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions.  We currently have Board authorization through May 31, 2011 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million.  During the quarter ended March 31, 2011, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

ITEM 6.     EXHIBITS

See Exhibit Index attached hereto. 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NORTHWEST NATURAL GAS COMPANY

(Registrant)

Dated:  May 4, 2011                                                     

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

41

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

To

Quarterly Report on Form 10-Q

For Fiscal Year Ended

March 31, 2011

Exhibit Number	Document
10.1	Carry and Earning Agreement by and between Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company, effective as of May 1, 2011, as amended by a First Amendment to C&E Agreement, dated March 22, 2011.
12	Statement re computation of ratios of earnings to fixed charges.
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in Extensible Business Reporting Language (XBRL): (i)Consolidated Statements of Income; (ii)Consolidated Balance Sheets; (iii)Consolidated Statements of Cash Flows; and (iv)Related notes.
	*Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in these XBRL documents is unaudited and that these are not the official publicly filed financial statements of Northwest Natural Gas Company. In accordance with Rule 402 of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

42

EX-10.1

March 22, 2011

Mr. James Zadvorny

Encana Oil & Gas (USA) Inc.

370 Seventeenth Street, Suite 1700

Denver, Colorado  80202

Re:           First Amendment to C&E Agreement

Dear Jim:

Northwest Natural Gas Company (“NWN”) and Encana Oil & Gas (USA) Inc. (“Encana”) have entered into that certain Carry and Earning Agreement dated and effective as of May 1, 2011 (“C&E Agreement”).  NWN and Encana anticipated executing Letters of Attornment relating to the Gathering Agreement and the Processing Agreement, as defined in the C&E Agreement.  In consideration of the execution of the Letters of Attornment, NWN and Encana have agreed to certain additional matters set forth in this Letter Agreement.  The terms of this Letter Agreement shall amend and be incorporated into the C&E Agreement.  All capitalized terms not defined in this Letter Agreement shall have the meanings set forth in the C&E Agreement and the Letters of Attornment, as applicable.

1.New Connections.  [***], Encana agrees that for so long as the C&E Agreement is in effect, all New Connections affecting Carry Wells shall be constructed at Encana’s sole cost and expense, as provided in Section 5.1 of the C&E Agreement.

2.Successor Shipper MDQ.  The written notice required by [***] of the [***] shall set Successor Shipper’s MDQ in the Successor Shipper Gas Gathering Agreement at 33,000 Mcf per Day unless NWN and Encana agree otherwise prior to executing the notice.

3.Successor Shipper Plant Capacity.  The written notice required by [***] of the [***] shall set Successor Shipper Plant Capacity in the Successor Shipper Gas Processing Agreement at 33,000 Mcf per Gas Day unless NWN and Encana agree otherwise prior to executing the notice.

4.[***]

5.[***]

6.Section 10.5 of the C&E Agreement.  Section 10.5 of the C&E Agreement shall be replaced in its entirety with the following:

10.5           Amendment of Gathering and Processing Agreement.  Prior to any election under Article VI.G. of the Operating Agreement by NWN to take its gas in kind, Encana may amend the

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

Gathering Agreement or Processing Agreement subject to the following:

(i)Encana may enter into any such amendment without the consent of NWN so long as such amendment does not affect NWN’s rights, costs or fees under the Gathering Agreement, Processing Agreement, or NWN’s rights, costs or fees under a future Successor Shipper Gas Gathering Agreement or Successor Shipper Gas Processing Agreement;

(ii)If Encana desires that NWN’s rights be subject to the amendment, Encana shall provide thirty (30) days advance written notice to NWN in order to provide NWN an opportunity to discuss with Encana the amendments in advance of and during negotiations.  The Parties acknowledge that [***], and because Encana has interests in multiple producing properties other than the Leases, amendments to the Gathering Agreement and Processing Agreement that may be of benefit to Encana will not provide equivalent benefit to NWN.  If the Parties agree on amendments to this Agreement that will place NWN in an equivalent economic position under this Agreement as before such amendment or amendments to the Gathering Agreement and Processing Agreement, then NWN shall agree to be bound by the proposed amendment to the Gathering Agreement or Processing Agreement.

Sincerely,

/s/

Barbara Cronise

Accepted and Agreed:

Encana Oil & Gas (USA) Inc.                                                                           Northwest Natural Gas Company

By: /s/                                                                                                    By: /s/                                            

*John Schopp                                                                              Gregg S. Kantor

  Vice President Chief Executive Officer

North Rockies Business Unit

*By Kurt S. Froistad

Attorney in Fact

Delegate

Carry and Earning Agreement

by and between

Encana Oil & Gas (USA) Inc.

a Delaware corporation

and

Northwest Natural Gas Company

an Oregon corporation

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

TABLE OF CONTENTS

SECTION 1.                         EXHIBITS 1

SECTION 2.                         DEFINITIONS 2

SECTION 3.                         CARRY WELLS  10

SECTION 4.                         TITLE AND OTHER INFORMATION  17

SECTION 5.                         OPERATIONS  18

SECTION 6.                         REPRESENTATIONS, WARRANTIES AND AGREEMENTS  19

SECTION 7.                         CONDITION SUBSEQUENT:  OPUC APPROVAL  24

SECTION 8.                         ADDITIONAL COVENANTS  24

SECTION 9.                         FORCE MAJEURE  24

SECTION 10.                          GAS GATHERING AND PROCESSING SERVICES, MARKETING  25

SECTION 11.                          INDEMNITIES  27

SECTION 12.                          TERM  27

SECTION 13.                          ASSIGNABILITY  27

SECTION 14. TERMINATION OF OBLIGATIONS TO FUND AND DRILL CARRY WELLS  28

SECTION 15.                          TAXES  29

SECTION 16.                          NOTICES  30

SECTION 17.                          RELATIONSHIP OF THE PARTIES  31

SECTION 18.                          ENTIRE AGREEMENT  31

Carry and Earning Agreement

Section 19.                      Governing Law; Venue for Disputes  31

SECTION 20.                          AMENDMENTS; WAIVER  31

SECTION 21.                          PUBLIC ANNOUNCEMENTS  31

SECTION 22.                          SEVERABILITY  32

SECTION 23.                          MUTUALITY  32

SECTION 24.                          DISPUTE RESOLUTION  32

SECTION 25.                          WAIVER OF SPECIFIED DAMAGES  33

SECTION 26.                          FURTHER ASSURANCES  33

SECTION 27.                          RULES OF CONSTRUCTION  33

SECTION 28.                          COUNTERPART EXECUTION  34

Carry and Earning Agreement

CARRY AND EARNING AGREEMENT

THIS CARRY AND EARNING AGREEMENT (this “Agreement”) dated and effective as of May 1, 2011 (the “Effective Date”) is by and between ENCANA OIL & GAS (USA) INC., a Delaware corporation (“Encana”) with an address of 370 17th Street, Suite 1700, Denver, Colorado 80202, and NORTHWEST NATURAL GAS COMPANY, an Oregon corporation (“NWN”) with an address of 220 NW Second Avenue, Portland, Oregon 97209-3991.  Encana and NWN shall be referred to in this Agreement, individually, as a “Party” and, collectively, as the “Parties.”

RECITALS

A.           Encana owns oil and gas Leasehold Interests in the “Updip Area” and the “Downdip Area,” as both are fully described in Exhibit A of this Agreement (collectively, the “Property”), within the Jonah Field in Sublette County, Wyoming, pursuant to the Leases identified in Exhibit A-1 of this Agreement.  The Property shall include any additional oil and gas Leasehold Interests which Encana acquires in the Downdip Area after the Effective Date, and Exhibit A-1 is subject to amendment in the event of any such acquisition.

B.           NWN desires to participate in the further development of the oil and gas Leasehold Interests in the Property by paying a portion of the costs incurred by Encana associated with the drilling of [***] Net Carry Wells on the Property in exchange for certain portions of Encana’s right, title and interest in the Leases, Carry Wells, and Existing Wells in the Updip Area, as well as in and to the wellbores of Carry Wells and the production from such wellbores in the Downdip Area.

C.           The Parties desire to enter into this Agreement to govern their rights and obligations with respect to exploration and development of the Property.

AGREEMENT

IN CONSIDERATION OF ONE HUNDRED DOLLARS ($100) and other good and valuable consideration, the receipt and sufficiency of which are acknowledged, the Parties agree as follows:

Section 1.Exhibits

The following Exhibits are attached to this Agreement and shall be considered part of this Agreement:

(i)Exhibit A – Property (with the Updip Area and Downdip Area described and also depicted on a map)

(ii)Exhibit A-1 – Lease Schedule

Page 1 of 35

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

(iii)Exhibit B-1 – Form of Wellbore Assignment

(iv)Exhibit B-2 – Form of Assignment and Stipulation of Interest

(v)Exhibit C – Form of Operating Agreement

(vi)Exhibit D – Disclosure Statement

(vii)Exhibit E – Wire Transfer Instructions for NWN Share

(viii)Exhibit F – Letters of Attornment

(ix)Exhibit G – Composite Producer Price Index Table

(x)Exhibit H – Drilling Schedule

Section 2.Definitions

The following terms shall have the following meanings:

2.1“Acquisition” is defined in Section 3.10 below.

2.2“AFE” shall mean an authorization for expenditure.

2.3“Affiliates” shall mean, with respect to any Person, any other Person that either directly or indirectly controls or manages, is controlled or managed by or is under common control or management with such first Person.  For purposes of the definition of “Affiliates,” “control” means the right or power to direct the policies of another through management authority, equity ownership, delegated authority, voting rights or otherwise.

2.4“Agreement” has the meaning set forth in the first paragraph of this Agreement.

2.5“Arbitrators” is defined in Section 24 below.

2.6“Assets” means (i) all of Encana’s right, title, and interest in and to the Leasehold Interests; (ii) all of Encana’s immovable personal property located on the Leasehold Interests used in connection with or attributable in any manner to the exploration or development of the Leasehold Interests for Gas or the operation of the Leasehold Interests or the treating, storing or transporting of Gas produced from the Leasehold Interests, excluding gathering lines; (iii) all of Encana’s rights with respect to any and all contracts, agreements, instruments, governmental orders and contractual rights insofar as they cover the Leasehold Interests; and (iv) all of Encana’s rights with respect to any and all easements, rights-of-way, rights, permits, licenses and servitudes insofar as they are used or held in connection with the exploration, development or operation of the Leasehold Interests or the transportation of Gas produced therefrom.  The term “Assets” shall not include any ownership interest in (a) gathering, dehydration, compression or treatment facilities beyond the wellhead installations; (b) any existing or future water disposal

Page 2 of 35

wells or water management facility(ies) located on the Property; or (c) Encana’s title to the severed surface lands in the S/2 and S/2N/2 of Section 32 except as may arise from a Lease, but shall include the right to use such facilities and lands described in (b), (c) and (d) insofar as they are necessary for the production, gathering and processing of Gas produced from the Leasehold Interests.

2.7“Assigned Section” is defined in Section 3.5 below.

2.8“Assignment and Stipulation of Interest” shall mean the Assignment and Stipulation of Interest attached to this Agreement as Exhibit B-2.

2.9“Basic Contracts” shall mean those agreements that are contractually binding arrangements to which the Assets are or may be subject and which will be binding on the Assets or NWN after the Effective Date (including, without limitation, farmout and farmin agreements, option agreements, forced pooling orders, assignments of production payments, unit agreements, joint operating agreements, gas balancing agreements, pooling agreements, communitization agreements, surface use agreements, letter agreements, indenture, bank loans, and credit agreements) and which may result in a potential positive or negative economic impact upon NWN in excess of $25,000 in any calendar year.  Pursuant and subject to Section 6.2(viii), Basic Contracts are listed in Section 6.2(viii) of the Disclosure Statement.

2.10“BLM” shall mean the Bureau of Land Management of the United States Department of the Interior.

2.11“Boundary Well” is defined in Section 3.11 below.

2.12INTENTIONALLY OMITTED

2.13“Carry Well” shall mean a well drilled pursuant to Section 3 of this Agreement and “Carry Wells” shall mean all wells drilled pursuant to Section 3 of this Agreement.  The term “Carry Well” and “Carry Wells” shall include, but not be limited to, any Post-Carry Well drilled pursuant to Section 3 of this Agreement.

2.14“Casualty Defect” means, with respect to all or any material portion of the Assets taken as a whole, any destruction by fire, blowout, leak, explosion or other casualty (above or below ground), or any taking, or pending or threatened taking, in condemnation or under the right of eminent domain, of all or any material portion of the Assets taken as a whole.

2.15“CDP” shall mean a central delivery point, referring to the facilities owned by Encana which will receive and dehydrate Gas from the Carry Wells and Existing Wells, remove Condensate, and deliver such Gas to the custody transfer meters owned by [***].

2.16“Composite PPI” shall mean the weighted average of the Producer Price Indices shown on Exhibit G attached to this Agreement, weighted in the proportions shown on Exhibit G attached to this Agreement.

Page 3 of 35

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

2.17“Condensate” shall mean those liquid hydrocarbons that are separated from the Gas at a CDP.

2.18“Costs of Completing” shall mean all costs of completing a well, including but not limited to, the costs of fracture stimulation and the drilling out of frac plugs with respect to such well.

2.19“Costs of Drilling” shall mean the following costs related to a well: costs of constructing and upgrading access roads, obtaining and preparing the location, obtaining permits and title opinions, obtaining drilling contractor services and consultants necessary for the drilling of such well, obtaining mud chemicals, pipe and supplies and all other costs and expenses associated with or incurred in moving in, rigging up, drilling, logging and testing so that a decision can be made to either attempt to set pipe and complete such well or to plug and abandon it as a dry hole.

2.20“Costs of Equipping” shall mean the costs of the acquisition and installation of the initial equipment for a well and the costs to tie the well into a CDP, which may include but is not limited to the wellhead and wellsite equipment (including but not limited to, flow lines, wellsite or CDP separation facilities, wellsite or CDP tanks and storage facilities, measurement equipment, meter connection facilities, power lines and electrical facilities, and expansions and improvements of such equipment) other than equipment required for gathering, regardless of when such cost is incurred and which costs are capitalized for federal income tax purposes.

2.21“Disclosure Statement” shall mean Exhibit D attached to this Agreement.

2.22“Downdip Area” has the meaning set forth in the first Recital above.

2.23“Downdip Carry Well” shall mean a Carry Well drilled within the Downdip Area.

2.24“Drilling Schedule” shall mean the drilling schedule set forth in Exhibit H to this Agreement.  All wells shown on the Drilling Schedule are intended to designate Net Carry Wells.

2.25“Effective Date” has the meaning set forth in the first paragraph of this Agreement.

2.26“Election Well” has the meaning set forth in Section 3.10 of this Agreement.

2.27“Encana” has the meaning set forth in the first paragraph of this Agreement.

2.28“Environmental Laws” shall mean all federal, state, county, or local laws, rules, regulations, ordinances and common law torts relating to (i) protection of the environment from pollution, (ii) the release, emission or control of any pollutant, (iii) solid, gaseous or liquid waste generation, handling, treatment, storage, disposal or transportation, (iv) exposure to hazardous, toxic, dangerous or other substances alleged to be harmful, (v) protection of wildlife, including threatened and endangered species, and (vi) protection and preservation of historic sites and

Page 4 of 35

objects.  The term “Environmental Laws” shall include, but not be limited to, the following statutes and the regulations promulgated thereunder:  the Clean Air Act, 42 U.S.C. § 7401, et seq., the Clean Water Act, 33 U.S.C. § 1251, et seq., the Resource Conservation and Recovery Act, 42 U.S.C. § 6901, et seq., the Superfund Amendments and Reauthorization Act, 42 U.S.C. § 11011, et seq., the Toxic Substances Control Act, 15 U.S.C. § 2601, et seq., the Water Pollution Control Act, 33 U.S.C. § 1251, et seq., the Safe Drinking Water Act, 42 U.S.C. § 300f, et seq., the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, 42 U.S.C. § 9601, et seq., the Oil Pollution Act of 1990, 33 U.S.C. § 2701, et seq., the Emergency Planning and Community Right-To-Know Act, 42 U.S.C. § 11001, et seq., the Endangered Species Act of 1973, 16 U.S.C. § 1531, et seq., the Migratory Bird Treaty Act, 16 U.S.C. § 703, et seq., and any other federal, state, county, or local laws, rules, regulations, ordinances, licenses, permits, judgments, writs, decrees, injunctions or orders relating to the protection of human health or the environment.

2.29“Existing Wells” shall mean those oil and gas wells which have been drilled, completed and placed on production in the Updip Area prior to the Effective Date, and all production, operating rights, personal property, and leasehold equipment, including but not limited to casing, wellhead equipment, fixtures and pipelines  owned by Encana and associated with such wells.

2.30“Force Majeure Event” shall mean an act of God, act of terrorism, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental action, restraint or inaction, the interruption or suspension of the receipt or delivery of natural gas due to the inability or failure of any party not a party to this Agreement to receive or deliver such gas, unavailability of equipment, or inability to gain access, ingress or egress to conduct operations(including without limitation delays in or inability to obtain permits, approvals or clearances (including without limitation permits or approvals related to the use of any specific fracture stimulation technology or methodology) from any Governmental Authority).

2.31“Gas” shall mean any mixture of gaseous hydrocarbons or of hydrocarbons and other gasses, in a gaseous state, consisting primarily of methane.

2.32“Gathering Agreement” shall mean that [***].

2.33“Governmental Authority” and “Governmental Authorities” shall mean the United States and the state, county, city and political subdivisions in which the Property is located and which exercise jurisdiction over the Property, and any agency, department, board or instrumentality thereof which exercises jurisdiction over the Property.

2.34“Hazardous Substances” shall mean any hazardous, toxic, or radioactive pollutant, material or waste defined in or listed under any Environmental Laws, including, without limitation, those elements or compounds which are contained in the list of hazardous substances adopted by the United States Environmental Protection Agency and the list of toxic pollutants

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

designated by the United States Congress or said agency and petroleum products, including without limitation, gasoline, fuel oil, diesel, heating oil, motor oil and waste oil.

2.35[***].

2.36“Lance Pool” shall mean the interval correlative to that shown on the Schlumberger Phasor Induction-SFL with Linear Correlation Log run on December 4, 1994 in the Stud Horse Butte No. 13-27 well located in the southwest quarter of the southwest quarter (SW1/4SW1/4) of Section 27, Township 29 North, Range 108 West, 6th P.M. which is from a depth of 7,975 feet (equivalent to a subsea -695 feet) to a bottom depth of 12,400 feet (-5,120 feet, subsea), as defined by the Wyoming Oil & Gas Conservation Commission in Cause No. 1, Order No. 1, Docket No. 84-2003 dated April 25, 2003.

2.37“Leases” and/or “Leasehold Interest” shall mean, collectively, any oil and gas lease interest and/or other mineral interest (including fee interests), surface drillsite tract or contractual right to earn such an interest within, upon or under those lands described on Exhibit A-1, including without limitation the leases described on Exhibit A-1 and all amendments, renewals, extensions, ratifications or replacements thereof, which is obtained or is earned by purchase, assignment, leasehold seismic option, extension, renewal, farmin, acreage contribution or by any other means by either Party to this Agreement, including without limitation all agreements granting, reserving or otherwise conferring rights to explore for, drill for, produce, take, use, market, share in the production of or the proceeds from the sale of oil and/or gas; and rights to acquire any of the foregoing rights.

2.38“Letters of Attornment” shall mean those letters in Exhibit F attached to this Agreement to be executed on or before the Effective Date by Encana, NWN and [***] and acknowledging Encana’s assignment of a portion of its Leasehold Interest to NWN.

2.39“Marketable Title” shall mean, as to each Leasehold Interest, such right, title and interest that (i) is deducible of record from the official records of Sublette County, Wyoming, and the official records of the BLM or the Wyoming Office of Lands and Investments, and is free from reasonable doubt to the end that a prudent person engaged in the business of the ownership, development, and operation of producing oil and gas properties with knowledge of all of the facts and their legal bearing would be willing to accept the same, (ii) entitles Encana to receive not less than the interest set forth in Exhibit A-1 as “Encana’s Net Revenue Interest” with respect to all of the oil, gas, and hydrocarbon minerals produced, saved, and marketedfrom the formations located on the Property for the productive life of the Property, (iii) obligates Encana to pay operating costs and expenses in an amount not greater than “Encana’s Working Interest” set forth in Exhibit A-1 with respect to such Leasehold Interest, and (iv) except for Permitted Encumbrances, is free and clear of all liens and encumbrances.

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

2.40“Marketing Agreement” shall mean that Marketing Agreement attached to the Operating Agreement as Exhibit H.

2.41“Material Adverse Effect” shall mean (i) any material diminution in the value of the Leasehold Interests, (ii) any material and adverse effect on the use or operation of the Property, or (iii) any material and adverse effect on the ability of Encana to perform its obligations under this Agreement, the Wellbore Assignments, the Assignments and Stipulations of Interest, and the Operating Agreement.

2.42“Material Change in Financial Condition” shall mean that a Party’s credit rating becomes downgraded to a rating of Ba1 or lower as defined by Moody’s Investors Service, and/or a rating of BB+ or lower as defined by Standard & Poor’s Financial Services.

2.43“Net Carry Well” shall mean (i) for a Carry Well drilled in which Encana and NWN collectively own One Hundred Percent (100%) of the working interest, one (1) Net Carry Well, (ii) for a Carry Well drilled in which Encana and NWN collectively own less than One Hundred Percent (100%) of the working interest, the fraction of one (1) Net Carry Well derived from the formulae set forth in Section 3.4 or 3.5, as applicable.  For purposes of the term “Net Carry Well” only, the term “Carry Well” shall not include Post-Carry Wells.

2.44“Net Revenue Interest” shall mean a percentage share of the Gas produced and saved from or attributable to a particular Lease or well, after deducting all royalties, overriding royalties, non-participating royalties, net profits interests, production payments, and other burdens on or payments out of production.

2.45“NGLs” shall mean those liquid hydrocarbons obtained by processing Gas after Gas leaves a CDP.

2.46“NWN” has the meaning set forth in the first paragraph of this Agreement.

2.47“NWN Gas” shall mean all Gas produced from or attributable to NWN’s interest in the Downdip Carry Wells and in the Assigned Sections, but excluding Condensate.

2.48“NWN Share” is [***].

2.49“Operating Agreement” shall mean the operating agreement attached to this Agreement as Exhibit C, executed as of the Effective Date of this Agreement.

2.50“OPUC” shall mean the Oregon Public Utilities Commission.

2.51“Party” and “Parties” have the meanings set forth in the first paragraph of this Agreement.

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

2.52“Permitted Encumbrances” shall mean:

(i)lessors’ royalties, overriding royalties, reversionary interests and similar burdens that (a) are of record on the Effective Date, (b) do not at any time reduce Encana’s Net Revenue Interest in any Lease (or wells located on any Lease) below the percentage identified in Exhibit A-1 as “Encana’s Net Revenue Interest” for that Lease (or wells located on that Lease), (c) do not at any time increase Encana’s Working Interest in any Lease (or wells located on any Lease) without a corresponding increase in Encana’s Net Revenue Interest for that Lease (or wells located on that Lease), and (d) do not cumulatively operate to materially reduce Encana’s Net Revenue Interest with respect to Gas produced from any Lease (or wells located on any lease) below the percentage identified in Exhibit A-1 as “Encana’s Net Revenue Interest” for that Lease (or wells located on that Lease);

(ii)liens, charges, encumbrances, contracts, agreements, instruments, obligations, and other matters that (a) are specifically described in Section 2.52(ii) of the Disclosure Statement as Basic Contracts, (b) do not at any time reduce Encana’s Net Revenue Interest in any Lease (or wells located on any Lease) below the percentage identified in Exhibit A-1 as “Encana’s Net Revenue Interest” for that Lease (or wells located on that Lease), (c) do not at any time increase Encana’s Working Interest in any Lease (or wells located on any Lease) without a corresponding increase in Encana’s Net Revenue Interest for that Lease (or wells loEcated on that Lease), and (d) do not cumulatively operate to materially reduce Encana’s Net Revenue Interest with respect to Gas produced from any Lease (or wells located on any lease) below the percentage identified in Exhibit A-1 as “Encana’s Net Revenue Interest” for that Lease (or wells located on that Lease);

(iii)liens for Taxes or governmental assessments that are not yet delinquent or are being contested in good faith by appropriate proceedings which effectively delay any enforcement thereof;

(iv)materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s, Tax, and other similar liens or charges arising by law or contract in the ordinary course of business securing current accounts payable (owing with respect to goods or services provided with respect to the Leasehold Interests) that are not more than sixty (60) days past the invoice or due date, whichever is earlier, unless being contested in good faith by appropriate proceedings which effectively delay any enforcement thereof;

(v)easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations that do not interfere materially with the operation, value or use of such Leasehold Interest; and

(vi)all rights reserved to or vested in any governmental, statutory or public authority to control or regulate any of the Leasehold Interests in any manner, and all applicable laws, rules and orders of Governmental Authority.

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For purposes of clauses (i) and (ii) above, a reduction in the interest of Encana with respect to Gas produced from a Lease listed in Exhibit A-1, or an increase in the portion of the costs and expenses relating to any such Lease that Encana is obligated to pay, shall not be material if the reduction or increase is 0.1% or less (by way of example, and without limiting the generality of the foregoing, if “Encana’s Net Revenue Interest” percentage shown in Exhibit A-1 for a unit or well is 88.0%, a reduction in the interest of Encana will not be material if Encana is entitled to receive not less than 87.9% of all Gas produced from such unit or well).

2.53“Person” shall mean an individual, corporation, partnership, limited liability company, association, joint stock company, pension fund, trust or trustee thereof, estate or executor thereof, unincorporated organization or joint venture, court or governmental unit or any agency or subdivision thereof, or any other legally recognizable entity.

2.54“Post-Carry Well” shall mean one or more additional wells which may or may not be drilled pursuant to Section 3.6 following the drilling and completion of [***] Net Carry Wells.

2.55“Processing Agreement” shall mean that First Amended and Restated Gas Processing Agreement between Enterprise Gas Processing, LLC, a Delaware limited liability company, and Encana dated March 21, 2007 but effective as of February 1, 2006.

2.56“Property” has the meaning set forth in the first Recital above.

2.57“Property Tax” has the meaning set forth in Section 15.1 below.

2.58“Quarterly Statement” has the meaning set forth in Section 3.6 below.

2.59“Redelivery Points” shall mean (i) [***], as defined in the [***], and (ii) as to NWN’s share of Residue Gas, as defined in the [***], the [***].

2.60“Reserve Report” shall mean the Year End 2010 Reserve Report prepared for Encana by Netherland, Sewell & Associates, Inc.  The term “Reserve Report” shall not include nor refer to any prior or subsequent reserve reports prepared for Encana by any other Person.

2.61“Rig Release Date” shall mean the date Encana releases the drilling rig from the wellbore of a Carry Well.

2.62[***]

2.63[***]

2.64[***]

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

2.65“Services” is defined in Section 10.1 below.

2.66“Tax” or “Taxes” means any and all federal, state, local, foreign or other ad valorem, real or personal property, gathering, transportation, pipeline regulating, gross receipts, severance, production, excise, heating content, carbon, environmental, occupation, sales, use, value added, fuel, franchise, employment, premium, windfall profits, excess profits, customs duties, capital stock, profits, withholding, social security (or similar), unemployment, disability, transfer, registration, estimated, alternative or add-on minimum, or other tax, government charge or assessment of any kind whatsoever imposed on or with respect to all or any part of the Leasehold Interests, the Gas produced from Leasehold Interests or the proceeds thereof, or activities in connection with the Leasehold Interests, regardless of the point at which or the manner in which or the Person against whom such taxes, charges or assessments are charged, collected, levied or otherwise imposed, and including any interest, penalties and additions thereto and any obligations to indemnify or otherwise assume or succeed to the liability of any other Person; provided, however, that Taxes shall not include federal and state net income taxes and any penalty or interest surcharges thereon.

2.67“Term” is defined in Section 12 below.

2.68“Third Party Failure” is defined in Section 5.3 below.

2.69“Total NWN Share” is Two Hundred Fifty Million Nine Hundred Twenty Thousand Dollars ($250,920,000).

2.70“Unspent NWN Share” shall mean the amount by which the NWN Share for a Carry Well exceeds the actual expended Costs of Drilling and Costs of Completing the Carry Well.

2.71“Updip Area” has the meaning set forth in the first Recital above.

2.72“Updip Carry Well” shall mean a Carry Well drilled in the Updip Area.

2.73“Wellbore Assignment” shall mean the wellbore assignment attached to this Agreement as Exhibit B-1.

Section 3.Carry Wells

3.1Drilling of Carry Wells.  During the Term of this Agreement, Encana shall designate and drill [***] Net Carry Wells in which NWN shall participate pursuant to the terms of this Agreement.  The location of each Carry Well shall be determined by Encana in its sole discretion, provided that (i) all Carry Wells shall be drilled within either the Updip Area or the Downdip Area on the Leases insofar as they are described in Exhibit A-1, unless NWN elects, under Section 3.10, to allow well(s) planned to be drilled within Acquisition lands to be designated as Carry Wells; (ii) Carry Wells shall be drilled within all areas of proved undeveloped reserves in the Updip Area, as designated in the Reserve Report, that have not been drilled on the Effective Date (i.e., [***] wells); (iii) Encana shall endeavor to drill [***] additional Carry Wells within areas of proved undeveloped reserves in the Updip Area that may

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be identified in subsequent reserve reports; and (iv) each Carry Well in the Downdip Area shall be drilled within an area of proved undeveloped reserves, as designated in the Reserve Report.

Encana shall drill all [***] Net Carry Wells prior to the fifth (5th) anniversary of the Effective Date, as such period may be extended by Force Majeure Events.  Encana shall drill no fewer than [***] Net Carry Wells in total during each of the first three (3) twelve- (12-) month periods following the Effective Date, and no fewer than [***] Net Carry Wells in total during each of the last two (2) twelve- (12-) month periods following the Effective Date.  If the number of Net Carry Wells actually drilled in any calendar quarter is less than the number shown on the Drilling Schedule, then Encana shall make commercially reasonable efforts to drill makeup Net Carry Wells in the next calendar quarter, in addition to the Net Carry Wells scheduled for that quarter on the Drilling Schedule.  If Encana drills more Net Carry Wells than shown on the Drilling Schedule in any calendar quarter, the excess Net Carry Well(s) can be credited to any other calendar quarter in which Encana drills fewer Net Carry Wells than scheduled on the Drilling Schedule.  Encana shall drill and complete, equip, tie in and produce, or plug and abandon the Carry Wells, with due diligence and reasonable dispatch in accordance with applicable laws and the Operating Agreement and in a good and workmanlike manner, in accordance with good oil field practice.  Encana shall act as a reasonable and prudent operator to complete each Carry Well within a reasonable and customary period of time without consideration of market prices for production.

Notwithstanding anything to the contrary in this Agreement, Encana shall not be required to drill Carry Wells and NWN shall not be required to pay the NWN Share, if Encana is unable to secure necessary permits for Carry Wells from any Governmental Authority.

3.2Costs of Carry Wells.  NWN agrees to pay Encana the NWN Share for each Carry Well drilled pursuant to this Agreement, chargeable in accordance with the Operating Agreement for the Costs of Drilling and Costs of Completing each Carry Well.  After [***] Net Carry Wells have been drilled, to the extent that NWN has not contributed the Total NWN Share, then Encana shall issue an AFE to NWN for the amount of such deficiency, to be applied to the Costs of Drilling and Costs of Completing one or more Post-Carry Wells.  [***].  Encana shall provide NWN with an AFE for Costs of Equipping each Carry Well, which shall be solely for information purposes, and NWN shall have no obligation to make any payment towards any such informational AFE.

Unless the obligation to fund and drill Carry Wells is terminated early pursuant to Section 14.1 or Section 14.3, NWN’s obligation to fund Carry Wells shall terminate when NWN has paid the Total NWN Share to Encana.

3.3Payment of NWN Share.  At least fifteen (15) days but no more than thirty (30) days prior to the anticipated spud date for each Carry Well, Encana shall issue to NWN an AFE that (i) identifies the well as a Carry Well, (ii) specifies the anticipated spud date, and (iii) provides a specific description of the location and the survey plat and wellbore diagram for the

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well.  In connection with any AFE, Encana agrees promptly to provide any additional information regarding the Carry Well that is reasonably requested by NWN.  NWN shall pay Encana the NWN Share (less any credit for an Unspent NWN Share as described in the following paragraph) for each Carry Well within fifteen (15) days after receipt of notice from Encana that such Carry Well has been spudded.  Payment shall be pursuant to the wiring instructions attached to this Agreement as Exhibit E.

As each Carry Well is drilled and completed, Encana shall apply the NWN Share to [***] of the amount invoiced by third parties [***].  After Encana closes its accounting for a Carry Well’s AFE, the Unspent NWN Share, if any, shall be shown as a credit towards the NWN Share on the AFE issued to NWN for the next Carry Well and shall reduce the amount NWN must pay on that AFE.

In the event NWN fails to timely pay all or a portion of the NWN Share (taking into account any credit for Unspent NWN Share from a prior Carry Well) for one or more Carry Wells, Encana shall give NWN written notice of such failure, and NWN shall have thirty (30) days thereafter to remedy the default.  If NWN fails to timely remedy the default, Encana may, at its sole discretion and upon notice to NWN, elect to terminate the obligation to fund and drill any future Carry Wells under this Agreement, and

(i)           if the Marketing Agreement is then in effect, Encana may withhold delivery of a sufficient amount of NWN’s share of production proceeds from the Updip Area and Downdip Area and apply such proceeds to offset the cumulative total delinquent amount due on the AFE(s) until such time as the delinquent amounts have been recouped, at which time Encana shall assign to NWN the interests provided by this Section 3 for the affected Carry Well(s), if Encana has not done so already; or

(ii)           whether or not the Marketing Agreement is in effect, Encana may elect to either

(1)           demand that NWN pay the cumulative total delinquent amount due on the AFE(s), and upon receipt of such amount Encana shall assign to NWN the interests provided by this Section 3 for the affected Carry Well(s), if Encana has not done so already; or

(2)           not demand that NWN pay the cumulative total delinquent amount due on the AFE(s), in which case Encana shall have no obligation to assign to NWN the interests provided by this Section 3 for the affected Carry Well(s) and may keep the Net Revenue Interest share of Gas that would have been assigned to NWN pursuant to this Section 3 for the affected Carry Well(s).

Any termination pursuant to this Section 3.3 shall not affect NWN’s rights and Encana’s obligations in relation to Carry Wells for which (a) the full NWN Share has been paid (taking into account any credit for Unspent NWN Share from a prior Carry Well) prior to the date of termination and (b) pursuant to the preceding paragraph, Encana recoups delinquent amounts out of production proceeds or receives payment of the total deliquent amount due on the AFE(s).

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The Leasehold Interests that NWN has earned under this Agreement shall continue to be governed by this Agreement and the Operating Agreement.  If Encana elects to terminate the obligation to fund and drill Carry Wells pursuant to the preceding paragraph, NWN shall pay [***] to Encana within thirty (30) days of receipt of written notice of termination from Encana under this Section 3.3, and such payment shall be the exclusive remedy for early termination of the obligation to drill Carry Wells under this Agreement due to NWN’s failure to timely pay the NWN Share.  The Parties agree that actual damages for early termination of the obligation to drill Carry Wells under this Agreement cannot be ascertained with certainty and intend for the payments to Encana under the preceding sentence to serve as liquidated damages for such default.

3.4NWN’s Earned Interest in Carry Wells and Leases in the Downdip Area.  In consideration of  NWN’s timely payment of the NWN Share for each Carry Well drilled in the Downdip Area, Encana shall promptly execute, acknowledge and deliver a Wellbore Assignment, effective as of the first day of the month following the Rig Release Date for each such Downdip Carry Well, assigning to NWN (i) Five Percent (5%) of eight-eighths (8/8ths) of the Leasehold Interest in the wellbore of such Downdip Carry Well together with Five Percent (5%) of “Encana’s Net Revenue Interest,” as set forth for the applicable Lease in Exhibit A-1, in the wellbore of such Downdip Carry Well, limited in depth to the interval correlative to the stratigraphic equivalent of the Lance Pool as encountered in each such Carry Well and excluding any right, title or interest in and to Condensate produced from such Carry Well, and (ii) the right to use the Assets insofar as they are necessary for the production, gathering and processing of Gas produced from such Carry Well, all subject to the terms and conditions of this Agreement and the Permitted Encumbrances in existence on the Effective Date including without reservation Basic Contracts that satisfy Section 2.52(ii).  Such percentages shall be proportionately reduced if any Carry Well is a Boundary Well or Election Well in which one or more third parties own a working interest by multiplying such percentages by a decimal fraction equal to (a) the cumulative working interest percentage of production in that Carry Well allocated to NWN and Encana, divided by (b) the total production from such Carry Well.  For a Boundary Well or Election Well drilled in the Downdip Area, the decimal fraction so calculated shall be the fraction of a Net Carry Well represented by such well for the purpose of  determining when [***] Net Carry Wells have been drilled.  With respect only to a Post-Carry Well, in the event the Post-Carry Well is drilled in the Downdip Area, then the Five Percent (5%) interests to be assigned to NWN in the Wellbore Assignment pursuant to this Section 3.4 for the Post-Carry Well shall be multiplied by a decimal fraction equal to (1) the amount of the cumulative Unspent NWN Share paid for that well [***].

Encana shall execute, acknowledge and deliver Wellbore Assignment(s) pursuant to this Section 3.4 once each calendar quarter for interests earned in the preceding calendar quarter.  Promptly thereafter, Encana shall cause the Wellbore Assignment(s) to be placed of record in the official records of the County Clerk and Recorder in Sublette County, Wyoming to effect the

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assignment and shall then promptly provide a copy of the recorded Wellbore Assignment(s) to NWN.  Additionally, Encana shall promptly prepare the federal/state assignment forms to transfer the applicable operating rights to NWN and file such documents in the appropriate BLM or Wyoming Office of State Lands and Investments office on behalf of NWN.NWN shall reimburse Encana promptly for any fees incurred in connection with the recording or filing of assignments on behalf of NWN.

3.5NWN’s Earned Interest in Updip Carry Wells and Leases.  In consideration of  NWN’s timely payment of the NWN Share for each Carry Well drilled in either the Updip Area or the Downdip Area, and without regard to the actual location of any Carry Well, Encana shall execute, acknowledge and deliver an Assignment and Stipulation of Interest effective as of the first day of the month following the Rig Release Date for such Carry Well, assigning to NWN (i) One and Two-Tenths Percent (1.2%) of eight-eighths (8/8ths) of the Leasehold Interest in the appropriate Assigned Section (as defined below in this Section 3.5) together with One and Two-Tenths Percent (1.2%) of “Encana’s Net Revenue Interest,” as set forth in Exhibit A-1, in such Assigned Section, limited in depth to the interval correlative to the stratigraphic equivalent of the Lance Pool and excluding any right, title or interest in and to Condensate produced from the Assigned Section, and (ii) the right to use the Assets insofar as they are necessary for the production, gathering and processing of Gas produced from the Assigned Section, all subject to the terms and conditions of this Agreement and the Permitted Encumbrances in existence on the Effective Date, including without reservation Basic Contracts that satisfy Section 2.52(ii).  Such percentages shall be proportionately reduced if any Carry Well is a Boundary Well or Election Well in which one or more third parties owns a working interest by multiplying such percentages by a decimal fraction equal to (a) the cumulative working interest percentage of production in that Carry Well allocated to NWN and Encana, divided by (b) the total production from such Carry Well.  For a Boundary Well drilled in the Updip Area, the decimal fraction so calculated shall be the fraction of a Net Carry Well represented by such well for the purpose of  determining when [***] Net Carry Wells have been drilled.  With respect only to a Post-Carry Well, in the event the Post-Carry Well is drilled in the Updip or Downdip Area, then the One and Two-Tenths Percent (1.2%) interests to be assigned to NWN in the Assignment and Stipulation of Interest pursuant to this Section 3.5 for the Post-Carry Well shall be multiplied by a decimal fraction equal to (1) the amount of the cumulative Unspent NWN Share paid for that well [***].

The Assignment and Stipulation of Interest shall cover the Leasehold Interest in Existing Wells in the Assigned Section (and, in the case of a Carry Well drilled in the Updip Area that triggers this Section 3.5, specifically including that Carry Well).

The “Assigned Section” shall initially be Section 32 until such time as the cumulative Leasehold Interest assigned to NWN by Encana in Section 32 reaches Forty-Five Percent (45%) of eight-eighths (8/8ths) of the Leasehold Interest in Section 32, after which the Assigned Section shall be Section 33, until such time as the cumulative Leasehold Interest assigned to NWN in Section 33 reaches Forty-Five Percent (45%) of eight-eighths (8/8ths) of the Leasehold Interest in Section 32, after which the Assigned Section shall be Section 34.  Any fraction of a Leasehold Interest percentage that NWN earns that would cause NWN’s cumulative Leasehold Interest to exceed Forty-Five Percent (45%) of eight-eighths (8/8ths) of the Leasehold Interest in Section 32 or 33 shall be assigned to Section 33 or 34, respectively.

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Encana shall execute, acknowledge and deliver Assignment(s) and Stipulation(s) of Interest pursuant to this Section 3.5 once each calendar quarter for interest earned in the preceding calendar quarter.  Promptly thereafter,  Encana shall cause the Assignment(s) and Stipulation(s) of Interest to be placed of record in the official records of the County Clerk and Recorder in Sublette County, Wyoming to effect the assignment and shall promptly provide a copy of the recorded Assignment(s) and Stipulation(s) of Interest to NWN.  Additionally, Encana shall promptly prepare the federal assignment forms to transfer the applicable operating rights to NWN and file such documents in the appropriate BLM office on behalf of NWN.  NWN shall reimburse Encana promptly for any fees incurred in connection with the recording of any assignment on behalf of NWN.

3.6Post-Carry Wells.  After [***] Net Carry Wells have been drilled, the cumulative Unspent NWN Share, if any, shall be used to drill one or more Post-Carry Wells.  Encana shall issue one or more AFEs to NWN for the cumulative Unspent NWN Share, provided that Encana shall not issue an AFE for a Post-Carry Well for more than the NWN Share.  Except as provided in this Section 3.6, the Parties’ rights and obligations vis-à-vis a Post-Carry Well shall be the same as for a Carry Well.  If a Post-Carry Well is drilled in the Downdip Area, the interest assigned to NWN in the Wellbore Assignment for that Post-Carry Well shall be calculated as provided in  Section 3.4.  If a Post-Carry Well is drilled in the Updip Area or the Downdip Area, the interest assigned to NWN in the Assignment and Stipulation of Interest for that Post-Carry Well shall be calculated as provided in Section 3.5.

3.7Quarterly Statements.  Within twenty (20) days of the first day of each calendar quarter following the Effective Date, Encana shall prepare and submit to NWN a statement (the “Quarterly Statement”) showing the drilling activity and earned interest on a quarterly and cumulative basis.  The Quarterly Statement shall identify (i) the number and legal location of all Carry Wells drilled in the prior three-month period, (ii) the status of each Carry Well, (iii) the amount NWN paid for each Carry Well, (iv) the Unspent NWN Share, if any, for each Carry Well, (v) the amount and location of Leasehold Interest and Net Revenue Interest earned pursuant to Sections 3.4 and 3.5 above, and (vi) the cumulative totals since the Effective Date for each of the foregoing.

3.8Example of Sections 3.4, 3.5 and 3.6.

(i)By way of illustration only, the following example shows the interests NWN would earn pursuant to Sections 3.4 and 3.5 during two hypothetical calendar quarters.

Assume that the first day of the month following the Rig Release Date for the following [***] Carry Wells falls in the first hypothetical calendar quarter:

●  [***]

●  [***]

●  [***]

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During that first quarter, NWN would have earned an assignment of (i) pursuant to Section 3.4, a 5% Leasehold Interest and corresponding Net Revenue Interest in the wellbores of the [***] Downdip Carry Wells, and (ii) pursuant to Section 3.5, a 6.0% Leasehold Interest (i.e., 1.2% multiplied by the five Carry Wells) and the corresponding Net Revenue Interest in all Carry Wells, all Existing Wells, and in Encana’s Leasehold Interest in Section 32, each assignment being effective on the first day of the month following the Rig Release Date of the respective Carry Well.

Assume that the first day of the month following the Rig Release Date for the following [***] Carry Wells falls in the second hypothetical calendar quarter:

●  [***]

●  [***]

●  [***]

●  [***]

During that second quarter, NWN would have earned an assignment of (i) pursuant to Section 3.4, a 5% Leasehold Interest and the corresponding Net Revenue Interest in the wellbores of the two Downdip Carry Wells, and (ii) pursuant to Section 3.5, a 7.2% Leasehold Interest (i.e., 1.2% multiplied by the six Carry Wells) and the corresponding Net Revenue Interest in all Carry Wells, all Existing Wells, and Encana’s Leasehold Interest in Section 32, each assignment being effective on the first day of the month following the Rig Release Date of the respective Carry Well.

(ii)By way of illustration only, the following example shows the interests NWN would earn  pursuant to Section 3.6 in a hypothetical situation:

Assume that after [***] Net Carry Wells have been drilled, the cumulative Unspent NWN Share equals $[***] and Encana drills [***] Post-Carry Well in the Downdip Area.  NWN would have earned an assignment of (i) pursuant to Sections 3.6 and 3.4, a 2.5% Leasehold Interest (i.e., [***] cumulative Unspent NWN Share divided by $2.46 million) and the corresponding Net Revenue Interest in the wellbore of the Post-Carry Well, and (ii) pursuant to Sections 3.6 and 3.5, a [***] Leasehold Interest (i.e., [***] cumulative Unspent NWN Share divided by $[***] in all Carry Wells, all Existing Wells, and Encana’s Leasehold Interest in Section 34, each assignment being effective on the first day of the month following the Rig Release Date of the Post-Carry Well.

3.9Tax Partnership.  On the date of execution of this Agreement, the Parties shall enter into a tax partnership agreement in the form set forth in Exhibit G to the Operating Agreement.

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3.10Subsequent Acquisitions in Downdip Area.  In the event Encana acquires an oil and gas Leasehold Interest or an option to acquire any oil and gas Leasehold Interest in the Downdip Area (“Acquisition”) prior to drilling [***] Net Carry Wells, Encana shall provide written notice of the terms, conditions, burdens, obligations and commitments associated with the Acquisition to NWN within thirty (30) days of the closing of the Acquisition.  If an Acquisition includes lands located within the Downdip Area and lands located outside the boundaries of the Downdip Area, the Acquisition shall be deemed to include only those lands located inside the Downdip Area for purposes of this Section 3.10, unless the Parties agree otherwise.  NWN shall have thirty (30) days after receipt of the notice to notify Encana whether NWN elects to participate in well(s) that Encana may elect to drill on the Acquisition lands (“Election Wells”).  Failure to provide such election notice within the thirty- (30-) day period will be deemed an election not to participate in any Election Well, and the interests acquired in the Acquisition will not be subject to this Agreement or the Operating Agreement.  If NWN elects to participate, the Election Well(s) will be considered to be drilled on the Leases as described in the first Recital above and will be deemed Carry Wells subject to the terms of the Agreement, provided that (i) an election by NWN to participate will be deemed consent and agreement by NWN to be bound by the terms, conditions, burdens, obligations and commitments of the Acquisition, (ii) Encana shall have no obligation to extend any warranty, representation or indemnification under this Agreement to NWN with respect to any Election Well, and (iii) NWN’s election to participate in any Election Well will be at its sole cost, risk, expense and liability.  If an Election Well is drilled and completed in a location in which Encana and NWN collectively own or acquire less than One Hundred Percent (100%) of the working interest, the NWN Share payable for such Carry Well, and the interests assigned to NWN for such Carry Well pursuant to Section 3.4 and 3.5 shall each be proportionately reduced according to the formulae provided in those Sections, and such decimal fraction so calculated shall be the fraction of a Net Carry Well represented by such Election Well for the purpose of  determining when [***] Net Carry Wells have been drilled.

3.11Boundary Line Wells.  In the event that a Carry Well is drilled and completed such that the bottomhole location is not in conformance with applicable setback requirements of the Wyoming Oil & Gas Conservation Commission, or if the well is in an approved spacing unit in which Encana and NWN collectively own less than One Hundred Percent (100%) of the working interest (“Boundary Well”), the NWN Share payable for such Carry Well, and the interests assigned to NWN for such Boundary Well pursuant to Section 3.4 or 3.5, as applicable, shall each be proportionately reduced according to the formulae in such Sections, and such fraction of a Net Carry Well shall be counted in determining when [***] Net Carry Wells have been drilled.

Section 4.Title and Other Information

4.1Title Information.  NWN shall have the right, but not the obligation, to review title documentation in Encana’s file relating to any Carry Well at any time.  Any title information provided to NWN by Encana is without warranty as to accuracy of title information.  Except as required by the Operating Agreement, Encana shall have no obligation to purchase new or supplemental abstracts of title.  Encana will undertake curative work in connection with title to

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the Carry Wells which is required by the Operating Agreement or any other operating agreement applicable to such Carry Well and which a reasonably prudent operator would undertake in a similar situation.  Encana shall use reasonable commercial efforts to ensure that no liens or encumbrances, other than Permitted Encumbrances, attach to the Updip Area or the Downdip Area prior to the time that all Carry Wells under this Agreement have been drilled and the respective assignments have been delivered, and to cause any such liens or encumbrances to be released reasonably promptly upon receipt of notice thereof.

4.2Assumption of Certain Obligations. Subject to the other provisions of this Agreement, NWN shall not assume and shall not take title to any interest in the Property from Encana subject to any obligation not listed on the Disclosure Statement.  To the extent such obligations are found to exist, Encana and NWN shall take such actions as are necessary to provide NWN with the full benefit of the transactions contemplated by this Agreement as if such obligation did not exist.

Section 5.Operations

5.1Operating Agreement.  Concurrent with the execution of this Agreement, Encana and NWN shall enter into the Operating Agreement that, subject to the terms of this Agreement, shall govern all operations for the Carry Wells and all Existing Wells in which NWN earns an interest pursuant to this Agreement.  Encana shall be designated as Operator under the Operating Agreement.  The Parties may record or file all documents reasonably required to perfect the Operator’s lien and NWN’s lien, including but not limited to (i) a detailed memorandum in the form attached to the Operating Agreement as Exhibit I that Encana shall promptly record in the official records of Sublette County, Wyoming, upon satisfaction of the condition subsequent identified in Section 7, and (ii) a financing statement in the form attached to the Operating Agreement as Exhibit J that shall be filed with the Delaware Secretary of State upon satisfaction of the condition subsequent identified in Section 7, both of which shall secure Encana’s obligations under the Operating Agreement.

As each Carry Well is drilled, completed and equipped as provided in Section 3.1, Encana and NWN shall each bear and pay its share of the costs and expenses of such Carry Well in accordance with this Agreement and the Operating Agreement, provided that, as between Encana and NWN, Encana shall bear One Hundred Percent (100%) of all capital costs for:

(i) equipment or improvements in the [***] beyond the wellhead of any well governed by the Operating Agreement (including without limitation the cost of connecting the wells to the [***]),

(ii)  equipment and improvements at the CDPs, and

(iii)  improvements to the [***].

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In addition, Encana shall bear [***] of all costs for  fines and/or penalties arising out of alleged violations of [***], without regard to whether such violation arose or was discovered prior to or during the Term of this Agreement.  Encana shall also bear [***] of costs for remediation or remedial action which exceed Twenty Thousand Dollars ($20,000) as lease operating expense incurred per incident.

Encana shall also bear and pay One Hundred Percent (100%) of the costs to [***] pursuant to this Agreement and [***] and to perform [***] in accordance with applicable laws, including but not limited to [***].

Provided NWN has timely paid the NWN Share for any specific Carry Well, NWN shall be entitled to, and Encana shall credit to the account of NWN, and unless Encana markets NWN Gas, deliver to NWN at the Redelivery Points its Net Revenue Interest share of Gas produced from each Carry Well drilled in the Downdip Area, and NWN’s cumulative Net Revenue Interest share of Gas produced from each Assigned Section from the effective date of the respective Wellbore Assignments and Assignments and Stipulations of Interest.

5.2Conflicts.  If there is any conflict between this Agreement and the Operating Agreement, this Agreement shall control.

5.3Sharing of Recoveries.  If Encana declares a Force Majeure Event pursuant to Section 9 as a result of the interruption or suspension of the receipt or delivery of Gas (or any of its constituents) due to the inability or failure of any party not a party to this Agreement to receive or deliver such Gas (a “Third Party Failure”), then in the event of the recovery by Encana of any damage amount or other compensation for a Third Party Failure, NWN shall be entitled to a share of such damage amount or compensation calculated based on NWN’s proportionate share of the volume of Gas from the Property affected as a percentage of the total volume of Gas affected.

Section 6.Representations, Warranties and Agreements

6.1Representations and Warranties.  Each Party, with respect to itself only, represents and warrants to the other Party the following:

(i)Existence.  Each Party is duly organized, validly existing and in good standing under the applicable laws of the State of its incorporation or formation, and is qualified to do business and is in good standing in the State of Wyoming and in every other jurisdiction where the failure to so qualify would have a Material Adverse Effect on its ability to execute, deliver and perform this Agreement and the other agreements contemplated in this Agreement.

(ii)Power.  Except for the required approval described in Section 7, each Party has all requisite power and authority to (a) own, lease or operate its assets and properties and to carry on the business as now conducted, and (b) enter into and perform its obligations under this Agreement and to carry out the transactions contemplated by this Agreement.

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(iii)Authority.  Each Party has taken (or caused to be taken) all acts and other proceedings required to be taken by such Party to authorize the execution, delivery and performance by such Party of this Agreement and the other agreements contemplated in this Agreement.  This Agreement has been duly executed and delivered by each Party and constitutes the valid and binding obligation of each Party, enforceable against such Party in accordance with its terms, except as enforceability may be limited by applicable bankruptcy, moratorium, reorganization or similar laws affecting the rights of creditors generally and by principles of equity, whether considered in a proceeding at law or in equity.  The execution, delivery and performance of this Agreement by each Party does not and will not (a) conflict with, or result in any violation of or constitute a breach or default (with notice or lapse of time, or both) under (1) any provision of the organizational documents of such Party, or (2) any applicable statute, law, rule, regulation, order, writ, judgment, decree, agreement, instrument or license applicable to such Party, except as would not have a Material Adverse Effect, or (b) require the submission of any notice, report, consent or other filing with or from any Governmental Authority or third persons, other than such consents as are customarily obtained after assignment of an interest similar to the Wellbore Assignment and Assignment and Stipulation of Interest.

(iv)Pending Matters.  Except as set forth in Section 6.1(iv) of the Disclosure Statement, there are no actions, suits or proceedings by a third party or a Governmental Authority pending or, to such Party’s knowledge, threatened against a Party which if decided unfavorably to such Party could have a Material Adverse Effect on the ability of such Party to execute, deliver or perform this Agreement or could materially affect its title to, or ownership or operation of the Property.

(v)Broker Fee.  No Party has incurred any obligation or liability, contingent or otherwise, (or taken any action) for any fee payable to a broker or finder with respect to the matters provided for in this Agreement or the other agreements contemplated in this Agreement which could be attributable to or charged to the other Party.  Each Party shall indemnify, defend and hold harmless the other Party from any claims, damages, liabilities, costs and expenses, including reasonable attorneys’ fees in the event the prior sentence should be or become untrue as to such Party.

(vi)Enforceability.  This Agreement has been duly executed and delivered by each Party.  This Agreement and the Operating Agreement constitute, and each Wellbore Assignment and Assignment and Stipulation of Interest will constitute, on the date of their respective executions, the legal, valid and binding acts and obligations of each Party, enforceable against each Party in accordance with its terms, subject, however, to bankruptcy, insolvency, reorganization, moratorium and other laws affecting creditors’ rights generally and to general principles of equity.

(vii)No Conflicts.  Encana’s execution, delivery and performance of this Agreement and the Operating Agreement, and each Wellbore Assignment and Assignment and Stipulation of Interest, and NWN’s execution, delivery and performance of this Agreement and the Operating Agreement will not (a) result in a breach of or constitute a default under any Lease or any agreement binding or affecting the Leasehold Interests, any indenture, bank loan, credit agreement or farmout agreement, program agreement or operating agreement, or any other material agreement or instrument to which either Encana or NWN is a party or by either Party or

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its respective properties may be currently bound or affected, (b) cause either Party to become obligated to, or to offer to, prepay, redeem or purchase any indebtedness, or (c) except as set forth in Section 6.2(vii) of the Disclosure Statement, result in or require the creation or imposition of any mortgage, lien, pledge, security interest, charge or other encumbrance upon or of any of the properties or assets of either Party (including the Leasehold Interests).  Neither Party is in default under any order, writ, judgment, decree, determination, indenture, agreement or instrument in any manner that now or in the future could reasonably be expected to have a Material Adverse Effect.

(viii)Governmental Approvals.  Except for approvals by Governmental Authorities that are customarily obtained after execution of the respective document and listed in Section 6.1(viii) of the Disclosure Statement, no authorization, consent, approval, license or exemption of, and no filing or registration with, any court or governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, is necessary for the valid execution and delivery by either Party of, or the performance by either Party of its respective obligations under this Agreement or the Operating Agreement that has not been obtained or performed or the period for objection thereto expired.

6.2Representations and Warranties of Encana.   Encana represents and warrants to NWN, and to any mortgagee or beneficiary under a deed of trust given by NWN, as of the Effective Date and on each date Encana executes, acknowledges, and delivers an assignment pursuant to Sections 3.4 and 3.5, the following:

(i)Disclosure.  Taken as a whole, and to the best of Encana’s knowledge based upon commercially reasonable inquiry, none of the information, memoranda, exhibits, reports, financial statements, and other data furnished by or on behalf of Encana to NWN in connection with the transactions described in this Agreement, including without limitation the Reserve Report, contains an untrue statement of a material fact or omits to state any material fact.  To the best of Encana’s knowledge based upon commercially reasonable inquiry, there is no material fact that has not been disclosed to NWN that might reasonably be expected to have a Material Adverse Effect.  The Leasehold Interests constitute all of the properties and interests of Encana within the Updip Area and the Downdip Area that are the subject of the Reserve Report, and, except for (a) production from the Property in the ordinary course of business, (b) matters listed in Section 6.2(i) of the Disclosure Statement, and (c) changes in the general market prices of oil and natural gas, no material adverse change in the condition of or remaining recoverable reserves attributable to the Property has occurred since the date of the Reserve Report.  Except for matters listed in Section 6.2(i) of the Disclosure Statement, no material adverse change in the financial condition, or results of operations or cash flows, of Encana has occurred since the date of the most recent audited financial statements delivered to NWN, if any.  The actions of Encana in furnishing information to NWN in connection with the transactions described in this Agreement do not and will not violate any duty owed by Encana to any Person to which such information relates or any obligation of Encana under any existing agreement, document, or instrument.

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(ii)Lessee Qualification.  Encana is qualified pursuant to federal and state law, as applicable, to own and operate federal and state oil and gas leases in the State of Wyoming, and is in good standing with, authorized by, and qualified with all Governmental Authorities with jurisdiction over operations on such oil and gas leases, to the extent Encana is required by such Governmental Authorities to so qualify and maintain good standing.

(iii)Status of Leases.  The Leases are in full force and effect, are valid and subsisting and cover the entire estate which they purport to cover.  Encana is not aware of any material alleged or actual default under any contract or agreement pertaining to the Property, including without limitation the Basic Contracts.  No party to any Lease has given to Encana or threatened to give notice of any action to terminate, cancel, rescind or procure judicial reformation of any Lease or of any provision thereof.

(iv)Marketable Title.  Encana represents and warrants that it holds Marketable Title to the Leasehold Interests as shown on Exhibit A-1 sufficient to convey to NWN the percentages of the working interest and Net Revenue Interest in the Leasehold Interests provided in Section 3 of this Agreement, provided that this warranty is personal to NWN and may not be conveyed by NWN.  Encana owns good title to the Assets, free and clear of any encumbrances, liens or security interests other than Permitted Encumbrances.

(v)Consents, Preferential Rights and Required Notices.  Except as disclosed in Section 6.2(v) of the Disclosure Statement, all consents and approvals necessary to permit the valid conveyance by Encana of the Leasehold Interests and execution and delivery of this Agreement and the Operating Agreement, and each Wellbore Assignment and Assignment and Stipulation of Interest, have been obtained (or deemed obtained, due to the time for exercising such preferential rights having expired).  Waivers of all preferential purchase rights affecting Encana’s right, title and interest in the Leasehold Interests have been obtained.  All advance notifications required to be given to third parties of the transactions contemplated in this Agreement and the Operating Agreement, and each Wellbore Assignment and Assignment and Stipulation of Interest, necessary to permit the valid conveyance to NWN of the Leasehold Interests and execution and delivery of this Agreement and the Operating Agreement, and each Wellbore Assignment and Assignment and Stipulation of Interest, have been timely and properly given.

(vi)Operations.  Neither the Existing Wells nor the Carry Wells that will be drilled pursuant to this Agreement are subject to any third-party operating agreements.

(vi)Commitments to Contracts.  Except as set forth in Section 6.2(vii) of the Disclosure Statement:

(a)no third party has any right to purchase from Encana any natural gas from the Property (including any call, right of first refusal or preferential right to purchase) that does not terminate within one month or is not terminable by Encana without penalty on notice of one month or less;

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 (b)neither the Leasehold Interests nor the Gas attributable to the Leasehold Interests are subject, committed, or dedicated to any joint operating, unitization, pooling, communitization or area of mutual interest agreement; and

(c)neither the Leasehold Interests nor the Gas attributable to the Leasehold Interests are subject, committed, or dedicated to any contract that will or could reasonably be expected to prevent or interfere with the ownership, exploration, development, operation, maintenance or use of any of the Leasehold Interests in accordance with prudent industry practices or in accordance with the manner in which such Leasehold Interest is currently being owned, explored, developed, operated, maintained or used.

(viii)Documents.  To the best of Encana’s knowledge upon commercially reasonable inquiry, (a) all Basic Contracts are listed on Section 6.2(viii) of the Disclosure Statement; (b) Encana has furnished or made available to NWN accurate and complete copies of all Basic Contracts; (c) all Basic Contracts are in full force and effect and are the valid and legally binding obligations of the parties to the Basic Contracts and are enforceable in accordance with their respective terms; (d) no default, event of default, or other similar condition or event (however described) exists or, with the lapse of time or the giving of notice, or both, would exist for any Basic Contracts; and (e) the execution and delivery of this Agreement and the consummation of the transactions contemplated by this Agreement will not result in a breach of, constitute a default under, or result in a violation of the provisions of any Basic Contract to which Encana is a party or any overriding royalty agreement applicable to those lands subject to the Leases.

(ix)Compliance with Laws.  Except as disclosed in Section 6.2(ix) of the Disclosure Statement, and to the best of Encana’s knowledge based upon commercially reasonable inquiry, (a) the Leasehold Interests have been and are being owned and operated, in all material respects, in accordance with all applicable laws, rules and regulations (including Environmental Laws) of all Governmental Authorities having or asserting jurisdiction relating to the Leasehold Interests or to the ownership and operation of the Leasehold Interests, and (b) Encana has obtained and is and has been in compliance in all material respects with all licenses, approvals and permits required under any such laws, and all licenses, approvals and permits are in full force and effect (including those relating to past or present treatment, storage, disposal or release of a Hazardous Substance into the environment).

(x)No Casualties.  During the last twelve (12) months, no Casualty Defect adversely affecting (a) the operation of the Leasehold Interests or (b) the ability of Encana to perform Encana’s obligations under this Agreement, the Wellbore Assignments, the Assignments of Leasehold and Wellbore Interests, and the Operating Agreement, has occurred.

(xi)ORRI Amendments.  The  overriding royalty agreements affecting the Leases that were subject to that certain Amendment of Assignments of Overriding Royalty Interests dated June 1, 2000 have been made subject to an amendment in the identical form to that certain Second Amendment of Assignments of Overriding Royalty Interest between Encana and  Joseph J. Scott Trust dated December 27, 2010.

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The representations and warranties provided in this Section 6.2 shall in no event be deemed waived or made ineffective by reason of NWN’s opportunity for or results from conducting due diligence prior to the execution of this Agreement.

Section 7.Condition Subsequent:  OPUC Approval

This Agreement shall have no force and effect unless and until the OPUC approves this Agreement in full and without modification in an order satisfactory to NWN.

Section 8.Additional Covenants

8.1Encana shall keep the representation and warranty in Section 6.2(iii) true until the obligations under Section 3 have been completed.

8.2Encana shall use commercially reasonable efforts to maintain the Leases in effect without liens or encumbrances arising after the Effective Date until all Carry Wells have been drilled and all assignments required by Sections 3.4 and 3.5 have been recorded.

8.3Encana shall not, during the Term, create or suffer any calls on production or contracts for sale of production encumbering NWN’s interest in all Existing Wells, Carry Wells, and any future wells drilled in the Updip Area which provide for the delivery of Gas at a price below the prevailing market price.

8.4Prior to drilling a Carry Well, Encana shall have obtained all consents, approvals, certificates, licenses, permits, and other authorizations of the necessary Governmental Authorities required for Encana to own, develop, operate, and maintain the Property insofar as it pertains to such Carry Well.

8.5Each Party shall take its pro-rata share of all Gas produced from the Property so as to not go out of balance.

8.6In all material respects, Encana shall use commercially reasonable efforts to ensure that Encana’s operations on the Property comply with all applicable laws, rules and regulations (including Environmental Laws) of all Governmental Authorities having or asserting jurisdiction relating to the Property.

8.7As to the overriding royalty interests owned by Encana affecting the Leases, if any, insofar as Leasehold Interests are assigned to NWN pursuant to this Agreement, Encana shall accept payment calculated pursuant to terms in the identical form to that certain Second Amendment of Assignments of Overriding Royalty Interest between Encana and  Joseph J. Scott Trust dated December 27, 2010.

Section 9.Force Majeure

If a Party is rendered unable, wholly or in part, by a Force Majeure Event to carry out its obligations under this Agreement, other than the obligations to make monetary payments and to

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Section deliver assignments of interests in the Carry Wells, the affected Party shall give the other Party prompt written notice describing the Force Majeure Event in reasonable detail.  Thereupon, the obligations of the Party giving notice, so far as it is affected by the Force Majeure Event, shall be suspended and any time periods provided for in this Agreement shall be extended for a period equal to the period of the continuance of the Force Majeure Event.  The affected Party shall use all reasonable diligence to remove the Force Majeure Event as quickly as practicable.  The requirement that any Force Majeure Event be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts or other labor difficulty by the Party affected, contrary to its wishes, and settlement or resolution of such matters shall be within the discretion of the affected Party.

Section 10.Gas Gathering and Processing Services, Marketing

10.1Provision of Services.  NWN Gas shall be gathered, processed and/or treated (“Services”) on facilities owned and operated by third parties pursuant to the [***] as the same may be amended from time to time.   The Parties shall execute, and Encana shall cause [***] and Enterprise Gas Processing, LLC to execute the Letters of Attornment.As provided in the Letters of Attornment, [***].  Subject to the terms of this Agreement, NWN shall bear its allocated share of the fees and costs for Services under the [***], including, without limitation, its allocated share of any fees and costs associated with the delivery of gas in violation of applicable gas quality specifications.  Production from Existing Wells operated by Encana or in which Encana has an interest at the Effective Date shall not be included for purposes of determining NWN’s allocated share of incremental capacity fees and costs, until such time as NWN may take assignment of any interest in such wells pursuant to Section 3.5 of this Agreement.  Encana shall invoice NWN on a monthly basis for NWN’s share of fees and costs incurred pursuant to this Section 10.1.  Except with respect to said fees and costs, Encana RELEASES and DISCHARGES NWN from any and all liabilities, losses, and costs suffered or sustained by Encana in connection with the provision of the Services pursuant to this Section 10.1.

10.2Redelivery Obligations and Conveyance of Rights to Encana.  With respect to the provision of Services for NWN Gas, the Parties agree as follows:

(i)Encana shall cause to be gathered and redelivered at the Redelivery Points NWN Gas less the Gas consumed and the Gas lost and unaccounted for (in proportion to NWN’s Net Revenue Interest in the wells from which the Gas was produced) in connection with the gathering of NWN Gas.  NWN shall be entitled to the [***] NWN Gas at the [***] will be redelivered to the Redelivery Points in the same manner as Encana’s gas.

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

(ii)Curtailments.  If the quantity of NWN Gas and all other Gas available for delivery at any point on the facilities exceeds the capacity of the facilities available to the Parties pursuant to the Gathering Agreement and Processing Agreement, then Encana shall, without liability, allocate the available capacity pro-rata by volume between Encana and NWN.  During any period when all or any portion of the Services are unavailable because of a Force Majeure Event, or maintenance, or if the third parties providing the Services determine that the operation of all or any portion of the facilities will cause injury or harm to persons or property or to the integrity of such facilities, NWN Gas may be curtailed on a pro-rata basis as described in this Section 10.2(ii) without liability.  As between Encana and NWN, if the processing of NWN Gas is partially or entirely interrupted pursuant to the Processing Agreement, the Gas produced from the Property that is delivered to Encana at the Redelivery Points shall be allocated between Encana and NWN based on their respective interests in the Property.

10.3Marketing Election.  NWN desires that Encana market NWN Gas for NWN, and Encana agrees that it will procure such marketing services under the terms of the Marketing Agreement.  [***].  For so long as the Marketing Agreement remains in effect, Encana shall be responsible for payment of all burdens applicable to NWN Gas.

10.4Take-In-Kind Election. NWN shall have the right but not the obligation to take its Gas in-kind at the Redelivery Points pursuant to Article VI.G. of the Operating Agreement.  If NWN makes an election to take its Gas in-kind, (i) the Marketing Agreement shall terminate, (ii) NWN shall remit to Encana [***], and (iii) NWN shall be responsible for making the necessary arrangements to dispose of NWN Gas at the Redelivery Points.

10.5Amendment of Gathering and Processing Agreements.  Encana may amend the Gathering Agreement or the Processing Agreement subject to the following:

(i)Encana may enter into any such amendment without the consent of NWN so long as such amendment does not affect the rights under the Gathering Agreement or the Processing Agreement as assigned under the Letters of Attornment;

(ii)If Encana desires that NWN’s rights be subject to the amendment, Encana shall provide thirty (30) days advance written notice to NWN in order to provide NWN an opportunity to discuss with Encana the amendments in advance of and during negotiations.  The Parties acknowledge that because [***], and because Encana has interests in multiple producing properties other than the Leases, [***].

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

Section 11.Indemnities

11.1[***].

11.2[***].

Section 12.Term

The “Term” of this Agreement shall begin on the Effective Date and shall continue in full force and effect until all Carry Wells and all wells in the Assigned Sections have been plugged and abandoned and those portions of the Property reclaimed in accordance with applicable law, subject to the provisions of Section 14 below.

Section 13.Assignability

Either Party may assign or transfer, by assignment, sale, farmout or otherwise, or pledge or encumber in any way, in whole or in part, any of its rights or obligations under this Agreement or its interests in the Property and Carry Wells without the prior written consent of the other Party provided that (i) the assignment or transfer shall be void unless the assignee or transferee is expressly made subject to and agrees to be bound by the terms of this Agreement; (ii) if Encana seeks to assign or transfer all or substantially all of its interest in the Property, the Updip Area, or the Downdip Area, it shall promptly provide written notice to NWN of this fact, and if NWN so desires, NWN may request that Encana market NWN’s interests in the Property, the Updip Area, or the Downdip Area on NWN’s behalf on the same terms as Encana is marketing its interests, subject to NWN bearing its proportionate share of any costs associated with such marketing; and (iii) if Encana assigns or transfers all or substantially all of its interest in the Property, NWN shall have the right to terminate the obligation to fund and drill Carry Wells under this Agreement.

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

Section 14.Termination of Obligations to Fund and Drill Carry Wells

14.1Right of Termination of Obligation to Fund and Drill Carry Wells.  The obligation to fund and drill Carry Wells under this Agreement may be terminated at any time, such termination to be effective upon delivery of a notice of termination by the terminating Party(ies):

(i)By mutual consent of the Parties;

(ii)By Encana pursuant to Section 3.3 above;

(iii)By NWN pursuant to Section 13 above;

(iv)By either Party if a Force Majeure Event delays the drilling of Carry Wells more than one (1) year;

(v)By NWN if drilling is more than [***] Net Carry Wells behind schedule for any reason, regardless of whether all or part of such delay is due to a Force Majeure Event, compared to the Drilling Schedule;

(vi)By either Party if the other Party has a Material Change in Financial Condition;

(vii)By Encana in the event that the monthly Composite PPI exceeds the Composite PPI from December 2010 by a factor of more than One Hundred Thirty Percent (130%) at any time after January 2014;

(viii)By NWN if it will prospectively lose substantially all of the benefit to its customers from drilling additional Carry Wells, as determined in OPUC proceedings approving the transaction, as a result of changes in tax laws governing this transaction or Environmental Laws governing the drilling of Carry Wells; or

(ix)By either Party in the event that IRS treatment of the tax partnership structure set forth in Exhibit G to the Operating Agreement removes substantially all of the tax benefits of the transaction.

14.2Effect of Termination; Survival of Provisions. If the obligation to fund and drill Carry Wells under this Agreement is terminated pursuant to Section 14.1, then neither Encana nor NWN shall have the obligation to fund or drill additional Carry Wells and Encana shall return any cumulative Unspent NWN Share to NWN within thirty (30) days after such termination; provided that if either Party is in material default of its obligations under this Agreement at the time this Agreement is so terminated, such defaulting Party shall continue to be liable to the other Party for damages or specific performance in respect of such default, except as provided in Section 3.3, and such liability shall not be affected by such termination.  Upon completion of the obligation to fund and drill Carry Wells, or upon earlier termination of the obligation to fund and drill Carry Wells pursuant to Section 14.1 or Section 14.3, the obligations under Section 3, Section 4, Section 6.1(iv), Section 6.1(v), Section 6.2 (except Sections 6.2(iv)

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[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

and 6.2(xi)), Section 8 (except Section 8.5-8.7), Section 15.2, Section 16, Section 17, Section 21, and Section 24 of this Agreement shall terminate, provided that the remainder of this Agreement shall continue in full force and effect until all Carry Wells and all wells in the Assigned Sections have been plugged and abandoned and those portions of the Property reclaimed in accordance with applicable law, including but not limited to Environmental Laws.  Following termination of Section 24, disputes under this Agreement shall be governed by the dispute resolution procedure in the Operating Agreement.

14.3Termination for Failure or Refusal to Drill Carry Wells.  In the event that Encana fails or refuses to designate and/or to drill Carry Wells as required by this Agreement for reasons other than those set forth in Section 9 or Section 14.1, and such failure or refusal is not remedied by Encana within thirty (30) days following receipt of written notice that NWN believes Encana is in default of its obligations to designate and/or drill Carry Wells, then NWN shall be entitled to compel specific performance of Encana’s obligations under this Agreement.  The Parties acknowledge that the Property and the rights conferred under this Agreement are unique and that, in the event of Encana’s failure or refusal to designate and/or to drill Carry Wells, NWN could not be made whole by monetary damages.

Section 15.Taxes

15.1Apportionment of Ad Valorem and Property Taxes.  Except as otherwise provided in this Section 15.1, all ad valorem real and personal property Taxes and similar obligations (“Property Taxes”), excluding gross product tax assessed pursuant to Wyoming Statutes § 39-13-102, with respect to the Leases and all property located on or used in connection with the Leases shall be borne by Encana.  Notwithstanding the foregoing, all Property Taxes with respect to any Downdip Carry Well or any interest in the Updip Area for a taxable period that includes the date on which an interest in such Downdip Carry Well or Updip Area is transferred to NWN pursuant to Sections 3.4 or 3.5 shall be apportioned between the Parties based upon (i) the total percentage interest in the Downdip Carry Well and the Updip Area that is transferred to NWN during such taxable period and (ii) the actual number of days during such taxable period that elapse before the date of transfer and the number of days in such taxable period after the transfer.  Encana shall be responsible for all Property Taxes apportioned to periods before the transfer and each of Encana and NWN shall be responsible for its percentage share of all Property Taxes apportioned to periods after the transfer.  If any refund, rebate or similar payment is received by Encana or NWN for Property Taxes that are apportioned between the Parties pursuant to this Section 15.1, such refund shall be apportioned between Encana and NWN in the same manner as Property Taxes for the period to which the refund relates.

15.2Sales Taxes. Each Party shall be liable for and shall bear any sales and use Taxes, conveyance, transfer and recording fees and real estate transfer stamps or Taxes that may be imposed on such Party with respect to any transfer of property pursuant to this Agreement.  All such Taxes shall be collected and remitted by each Party respectively as required under applicable law.

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Section 16.Notices

All notices and communications required or permitted under this Agreement shall be in writing addressed as indicated below, and any communication or delivery made pursuant to this Section 16 shall be deemed to have been duly delivered upon the earliest of:  (i) actual receipt by the Party to be notified; (ii) three days after deposit with the U.S. Postal Service, certified mail, postage prepaid, return receipt requested; (iii) if by facsimile transmission, upon written confirmation of receipt by the receiving Party; or (iv) two days after deposit with Federal Express overnight delivery (or other reputable overnight delivery service), postage prepaid, return receipt requested.  Addresses for all such notices and communication shall be as follows:

To Encana:                      Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, Colorado  80202

Attention:  Team Lead Land, North Rockies Business Unit

Fax:   720.876.4551

With a copy of all notices to:

Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, Colorado  80202

Attention:  Debbie Nichols

Fax:   720.876.6009

To NWN:                      Northwest Natural Gas Company

220 NW Second Avenue

Portland, Oregon 97209-3991

Attention:  Randolph Friedman, Director, Gas Supply

Fax:           503.220.2584

With a copy of all notices to:

Northwest Natural Gas Company

220 NW Second Avenue

Portland, Oregon 97209-3991

Attention:  MardiLyn Saathoff

Fax:           503.220.2584

Either Party may, upon written notice to the other Party, change the address and person to whom such communications are to be directed.

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Section 17. Relationship of the Parties

This Agreement is not intended to create, and shall not be construed to create, an association for profit, a trust, a joint venture, a mining partnership or other relationship of partnership, or entity of any kind between the Parties.  Notwithstanding anything to the contrary contained in this Agreement, the Parties understand and agree that the arrangement and undertakings evidenced by this Agreement, taken together, result in a partnership for purposes of federal income taxation and for purposes of certain state income tax laws which incorporate or follow federal income tax principles as to tax partnerships.  For these purposes, the Parties agree to be governed by the tax partnership provisions in Exhibit G of the Operating Agreement, which are incorporated into this Agreement and made a part of this Agreement by this reference.  For every purpose other than the above-described income tax purposes, however, the Parties understand and agree that the liabilities of the Parties shall be several, not joint or collective, and that each Party shall be solely responsible for its own obligations except as otherwise provided in this Agreement.  In the event of any conflict or inconsistency between the terms and conditions in Exhibit G of the Operating Agreement and the terms and conditions of this Agreement or any attachment or exhibit to this Agreement, the terms and conditions in Exhibit G of the Operating Agreement shall govern and control.

Section 18.Entire Agreement

This Agreement and the exhibits to this Agreement contain the entire agreement of the Parties with respect to the subject matter of this Agreement and supersede all previous agreements or communications between the Parties, verbal or written, with respect to the subject matter of this Agreement.

Section 19.Governing Law; Venue for Disputes

This Agreement shall be governed by and construed and interpreted in accordance with the laws of the State of Wyoming, without reference to its conflicts of laws provisions.

Section 20.Amendments; Waiver

No amendments or other modifications or changes to this Agreement shall be effective or binding on either Party unless the same shall be in a writing executed by both Parties.  No waiver by either Party of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different nature.

Section 21.Public Announcements

Unless otherwise agreed or required by law as determined either Party, neither Party shall make any public announcement or statement with respect to this Agreement or the transactions contemplated by this Agreement without the consent of the other Party, provided that the non-announcing Party shall be afforded an opportunity to review and comment upon any required public announcement or statement prior to the announcement or statement being made.  A Party

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shall obtain the consent of the other Party prior to including such other Party’s name in a press release issued at any time.

Section 22.Severability

If a court of competent jurisdiction determines that any clause or provision of this Agreement is void, illegal, unenforceable or unconscionable under any present or future law (or interpretation thereof), the remainder of this Agreement shall remain in full force and effect, and the clauses or provisions that are determined to be void, illegal, unenforceable or unconscionable shall be deemed severed from this Agreement as if this Agreement had been executed with the invalid provisions eliminated; provided, however, that notwithstanding the foregoing, if the removal of such provisions destroys the legitimate purposes of this Agreement, then this Agreement shall no longer be of any force or effect.  The Parties shall negotiate in good faith for any required modifications to this Agreement required as a result of this provision.

Section 23.Mutuality

The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them.  Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by either Party.

Section 24.Dispute Resolution

The Parties agree to resolve all disputes concerning or relating to this Agreement pursuant to the provisions of this Section 24.  The Parties agree to submit all disputes to binding arbitration in Denver, Colorado.  The arbitration will be conducted according to the procedure that follows.  The arbitration proceedings shall be governed by Wyoming law and shall be conducted in accordance with the rules for Non-Administered Arbitration of Business Disputes published by The Center for Public Resources, Inc., with discovery to be conducted in accordance with the Federal Rules of Civil Procedure, and with any disputes over the scope of discovery to be determined by the Arbitrators (as defined below in this Section 24).  The arbitration shall be before a single Arbitrator chosen by the mutual agreement of the Parties, or if no agreement as to the identity of the Arbitrator can be reached within ten (10) days, a three- (3-) person panel of neutral Arbitrators, consisting of one person chosen by each Party, and the two Arbitrators so selected choosing the third.  The panel so chosen or the single person are referred to in this Agreement as the “Arbitrators.”  The Arbitrators shall conduct a hearing no later than sixty (60) days after submission of the matter to arbitration, and the Arbitrators shall render a written decision within thirty (30) days of the hearing.  At the hearing, the Parties shall present such evidence and witnesses as they may choose, with or without counsel.  Adherence to formal rules of evidence shall not be required, but the Arbitrators shall consider any evidence and testimony that they determine to be relevant, in accordance with procedures that they determine to be appropriate.  Any award entered in the arbitration shall be made by a written opinion stating the reasons and basis for the award made and any payment due pursuant to the arbitration shall be made within fifteen (15) days of the decision by the Arbitrators.  The decision of the Arbitrators shall be binding on the Parties, final and non-appealable, and may be filed in a court

Page 32 of 35

of competent jurisdiction and may be enforced by either Party as a final judgment of such court.  Each Party shall bear its own costs and expenses of the arbitration, provided, however, that the costs of employing the Arbitrators shall by shared equally by the Parties.

Section 25.Waiver of Specified Damages

FOR THE AVOIDANCE OF DOUBT, EACH PARTY EXPRESSLY DISCLAIMS, WAIVES AND RELEASES THE OTHER PARTY FROM ITS OWN EXEMPLARY, PUNITIVE, REMOTE OR SPECULATIVE DAMAGES OR ANY OTHER DAMAGES THAT ARISE SOLELY FROM THE SPECIAL CIRCUMSTANCES OF THE PARTY WHICH MAY NOT HAVE BEEN COMMUNICATED TO THE OTHER PARTY RELATING TO, ASSOCIATED WITH, OR ARISING OUT OF THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. NO LAW, THEORY, OR PUBLIC POLICY SHALL BE GIVEN EFFECT WHICH WOULD UNDERMINE, DIMINISH, OR REDUCE THE EFFECTIVENESS OF THE FOREGOING WAIVER, IT BEING THE EXPRESS INTENT, UNDERSTANDING, AND AGREEMENT OF THE PARTIES THAT SUCH DAMAGE WAIVER IS TO BE GIVEN THE FULLEST EFFECT, NOTWITHSTANDING THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), GROSS NEGLIGENCE, WILLFUL MISCONDUCT, STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY PARTY.

Section 26.Further Assurances

The Parties shall execute, acknowledge and deliver or cause to be executed, acknowledged and delivered such instruments and take such other action as may be necessary or advisable to carry out their obligations under this Agreement and under any document or other instrument delivered pursuant to this Agreement.

Section 27.Rules of Construction

The headings of the articles and sections of this Agreement are for guidance and convenience of reference only and shall not limit or otherwise affect any of the terms or provisions of this Agreement.  All references in this Agreement to articles, sections, subsections and other subdivisions refer to corresponding articles, sections, subsections and other subdivisions of this Agreement unless expressly provided otherwise.  Titles appearing at the beginning of any of such subdivisions are for convenience only and shall not constitute part of such subdivisions and shall be disregarded in construing the language contained in such subdivisions.  Unless the context otherwise requires, “including” and its grammatical variations mean “including without limitation”; “or” is not exclusive; words in the singular form shall be construed to include the plural and vice versa; words in any gender include all other genders; references in this Agreement to any instrument or agreement refer to such instrument or agreement as it may be from time to time amended or supplemented; and references in this Agreement to any Person include such Person’s successors and assigns.  All references in this Agreement to exhibits refer to exhibits attached to this Agreement unless expressly provided otherwise.  This Agreement has been drafted with the joint participation of Encana and NWN

Page 33 of 35

and shall be construed neither against nor in favor of either such Party but in accordance with the fair meaning thereof.

Section 28.Counterpart Execution

This Agreement may be executed by signing an original or a counterpart thereof.  If this Agreement is executed in counterparts, all counterparts taken together shall have the same effect as if all the Parties had signed the same instrument.

[Remainder of page intentionally left blank.]

Page 34 of 35

This Agreement is executed and effective as of the Effective Date.

Encana:                                                                NWN:

Encana Oil & Gas (USA) Inc.                                                                Northwest Natural Gas Company

By: /s/                                                                By: /s/                                               

John Schopp                                                                   Gregg S. Kantor

Vice President Chief Executive Officer

North Rockies Business Unit

Page 35 of 35

Exhibit A

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Property

Updip Area:                                           Township 29 North, Range 108 West of the 6th P.M.

Section 32:  All

Section 33:  All

Section 34:  All

Downdip Area:                                Township 29 North, Range 108 West of the 6th P.M.

Section 9:    All

Section 10:  All

Section 11:  SW/4

Section 14:  All

Section 15:  All

Section 16:  All

Section 17:  All

All within Sublette County, Wyoming.

Page 1 of 2

Carry and Earning Agreement – Exhibit A

Page 2 of 2

Carry and Earning Agreement – Exhibit A

Exhibit A-1

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Lease Schedule

A)      Lessor:                           USA WYW 125944

Lessee:                           High Plains Energy Company

Effective Date:                           January 1, 1992

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 32:                      All

Section 33:                      All

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 78.462481%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 9.037519%

B) Lessor: USA WYW 100902

Lessee:                           Eugene J. Wait, Jr.

Effective Date:                           August 1, 1986

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 34:                      All

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 77.182501%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 10.317499%

Page 1 of 4

Carry and Earning Agreement – Exhibit A-1

C)      Lessor:                           USA WYW 128703

Lessee:                           McMurry Oil Company

Effective Date:                           March 1, 1993

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 10:  NE/4, SW/4

Section 14:  NE/4, N/2SW/4

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 78.462481%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 9.037519%

D)      Lessor:                           USA WYW 118154

Lessee:                           Home Petroleum Corporation

Effective Date:                           December 1, 1989

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 9:  NE/4, SW/4

Section 17: NE/4, SW/4

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 78.462481%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 9.037519%

Page 2 of 4

Carry and Earning Agreement – Exhibit A-1

E)      Lessor:                           USA WYW 144998

Lessee:                           McMurry Oil Company

Effective Date:                           May 1, 1992

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 11:  SW/4

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 78.462481%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 9.037519%

F)      Lessor:                           USA WYW 127749

Lessee:                           McMurry Oil Company

Effective Date:                           November 1, 1992

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 15:  NE/4, SW/4

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 78.462481%

Burdens of Record:

Royalty Interest - Minerals Management Service: 12.500000%

Overriding Royalty Interests: 9.037519%

Page 3 of 4

Carry and Earning Agreement – Exhibit A-1

G)      Lessor:                           St WY 92 00196

Lessee:                           McMurry Oil Company

Effective Date:                           April 1, 1992

Description:                           Only insofar as the lease covers

Township 29 North, Range 108 West, 6th P.M.

Section 16:  NE/4, SW/4

Encana’s Working Interest: 100%

Encana’s Net Revenue Interest: 77.419173%

Burdens of Record:

Royalty Interest: 16.666667%

Overriding Royalty Interests: 5.914160%

Page 4 of 4

Carry and Earning Agreement – Exhibit A-1

Exhibit B-1

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011 by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Wellbore Assignment and Conveyance

In this WELLBORE ASSIGNMENT AND CONVEYANCE (“Assignment”) dated effective as of 7:00 a.m. Mountain Standard Time on the date(s) set forth on Exhibit A attached hereto, (each individually, the respective “Effective Date”), Encana Oil & Gas (USA) Inc., whose address is 370 17th Street, Suite 1700, Denver, CO  80202 (“Assignor”) for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, does hereby GRANT, BARGAIN, SELL, TRANSFER, ASSIGN, AND CONVEY unto Northwest Natural Gas Company, whose address is 220 N.W. Second Avenue, Portland, Oregon 97209-3991 (“Assignee”)  the following  (collectively, the “Assigned Interests”):

a.   For each well and associated wellbore described on the attached Exhibit A (each, individually, a “Well” and collectively, the “Wells”), the working interest and Net Revenue Interest set forth therein as to the gaseous hydrocarbons found in the stratigraphic equivalent of the Lance Pool as encountered in each Well, defined as the interval correlative to that shown on the Schlumberger Phasor Induction-SFL with Linear Correlation Log run on December 4, 1994 in the Stud Horse Butte No. 13-27 well located in the southwest quarter of the southwest quarter of Section 27, Township 29 North, Range 108 West, 6th P.M. Sublette County, Wyoming, which is from a depth of 7,975 feet (equivalent to a subsea -695 feet) to a bottom depth of 12,400 feet (-5,120 feet, subsea), as defined by the Wyoming Oil & Gas Conservation Commission in Cause No. 1, Order No. 1, Docket No. 84-2003 dated April 25, 2003, but excepting and excluding any right, title or interest in and to those liquid hydrocarbons that are separated from the gas at a central delivery point.

b.   The rights in and to the oil and gas leases described on the attached Exhibit A (“Leases”), insofar and only insofar as said Leases are necessary to operate, maintain, produce and plug and abandon the Wells, but excepting and excluding any right, title or interest in and to those liquid hydrocarbons that are separated from the gas at a central delivery point.

c.   The interests in and to the personal property and fixtures associated with the Wells, including without limitation the following: tubing, casing and other equipment in the wellbore, and wellhead equipment.

Page 1 of  5

Carry and Earning Agreement – Exhibit B-1

d.All rights under the Gathering Agreement and Processing Agreement, insofar as they relate to the properties and interests described in paragraphs (a) through (c) above and are assigned to Assignee pursuant to the Letters of Attornment attached to the Carry and Earning Agreement.

e.   All surface and subsurface rights incident or appurtenant to the to the properties and interests described in paragraphs (a) through (c) above, and all of Assignor’s right, title and interest in and to all easements, rights-of-way, permits, licenses, servitudes or other similar interests affecting the properties and interests described in paragraphs (a) through (c) above insofar as they are necessary for the production of gas from the Wells.

f.   The right to use the Assets insofar as is necessary for the production, gathering and processing of gas produced from the Wells.

Assignor and Assignee further agree as follows:

1.   This Assignment is made and accepted subject to, and Assignee assumes the Permitted Encumbrances to which the Leases may be subject to, to the extent the Permitted Encumbrances cover and affect the Assigned Interests.

2.   Assignee accepts the Assigned Interests subject to all of the express and implied covenants and obligations of the Leases, insofar as they relate to the Assigned Interests.  Furthermore, Assignee accepts the Assigned Interests subject to the terms and conditions of all existing valid orders, rules, regulations and ordinances of federal, state and other governmental agencies if any, which cover and affect the Assigned Interests.

3.   Assignor warrants title as against all parties claiming an interest in the Assigned Interests by, through or under Assignor.  This Assignment is made with full substitution and subrogation of Assignee in and to all covenants and warranties made or given by others before the Effective Date.

4.   This Assignment is made in accordance with, and is subject to all the terms, provisions, and conditions of that certain Carry and Earning Agreement dated and effective as of May 1, 2011, by and between Assignor and Assignee (“Carry and Earning Agreement”) which is incorporated by this reference the same as though fully set out in this Assignment.  Capitalized terms not otherwise defined in this Assignment shall have the meanings provided in the Carry and Earning Agreement.  However, this Assignment is neither intended as, nor shall it be deemed to accomplish, a merger of the terms and provisions directly set out in this Assignment and the terms and provisions of said Carry and Earning Agreement.  Should there be any conflict between this Assignment and the Carry and Earning Agreement, the terms and conditions set out in the Carry and Earning Agreement shall prevail.  This Assignment is subject to the terms of the [***].

5.   This Assignment is made in accordance with and is subject to that certain unrecorded Operating Agreement dated effective May 1, 2011 and attached to the Carry and Earning Agreement as Exhibit C.   Should there be any conflict between this Assignment and the foregoing Operating Agreement, the terms and conditions set out in this Assignment shall prevail.

Page 2 of 5

Carry and Earning Agreement – Exhibit B-1

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

6.   The Assigned Interests do not include, and Assignor does not intend to assign and Assignee does not intend to receive, any interest in the following to the extent that such items do not directly relate to the operation of, and production of gas from, a Well:  all lands, minerals, oil and gas leases and lands pooled therewith, units, working interests, executory interests, reversionary interests, net profits interests, net revenue interests, term interests, royalty and overriding royalty interests, fee interests, surface interests, and any other interests of a similar nature, all contracts, agreements, licenses, and servitudes, all easements, leases, surface use, and right-of-way agreements, all other property and equipment not directly used in connection with the operation of, and production from, the Wells and any and all rights not expressly in this Assignment conveyed as part of the Assigned Interests.

7.   The references in this Assignment to liens, encumbrances, burdens, defects, agreements and other matters shall not be deemed to recognize or create any rights in third parties or merge with, modify, or limit the rights of Assignor or Assignee, as between themselves.

8.   This Assignment may be executed by signing an original or a counterpart of an original. If this Assignment is executed in counterparts, all counterparts taken together shall have the same effect as if Assignor and Assignee had signed the same instrument.

TO HAVE AND TO HOLD the assigned interest unto Assignee and its successors and assigns, subject to all the express and implied covenants and obligations of the Leases and this Assignment.

[Remainder of page intentionally left blank.]

Page 3 of 5

Carry and Earning Agreement – Exhibit B-1

EXECUTED this ___ day of ____20__, but effective as of the Effective Date(s) set forth on the attached Exhibit A .

ENCANA OIL & GAS (USA) INC.

By:_________________________________________

Constance D. Heath, Attorney in Fact

ACKNOWLEDGEMENT

STATE OF COLORADO                                                      §

§

CITY AND COUNTY OF DENVER                                                                §

BEFORE ME, the undersigned authority, on this day personally appeared Constance D. Heath, Attorney-in-Fact for ENCANA OIL & GAS (USA) INC., known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that she executed the same for the purposes and consideration therein expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this _________ day of __________ 20__.

MY COMMISSION EXPIRES:

______________________________                                                                

Notary Public in and for the State of Colorado

Page 4 of 5

Carry and Earning Agreement – Exhibit B-1

NORTHWEST NATURAL GAS COMPANY

By: ________________________________________

Name/Title:

ACKNOWLEDGEMENT

STATE OF §

 §

COUNTY OF §

BEFORE ME, the undersigned authority, on this day personally appeared _____________________, as ________________ for NORTHWEST NATURAL GAS COMPANY known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same for the purposes and consideration therein expressed and in the capacity therein stated.

__________ 20__.

MY COMMISSION EXPIRES:

______________________________                                                                           

Notary Public

Page 5 of 5

Carry and Earning Agreement – Exhibit B-1

Exhibit B-2

Attached to and made a part of that Carry and Earning Agreement

  dated and effective as of May 1, 2011 by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Assignment and Stipulation of Interest

In this ASSIGNMENT AND STIPULATION OF INTEREST (“Assignment”) dated effective as of 7:00 a.m. Mountain Standard Time on the date(s) set forth on Exhibit A attached hereto, (each individually, the respective “Effective Date”), Encana Oil & Gas (USA) Inc., whose address is 370 17th Street, Suite 1700, Denver, CO  80202 (“Assignor”) for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, does hereby GRANT, BARGAIN, SELL, TRANSFER, ASSIGN, AND CONVEY unto Northwest Natural Gas Company, whose address is 220 N.W. Second Avenue, Portland, Oregon 97209-3991 (“Assignee”) the following (collectively, the “Assigned Interests”):

a.   For the lands described in Part I of the attached Exhibit A (the “Property”), the working interest and Net Revenue Interest set forth in Part II of the attached Exhibit A to the gaseous hydrocarbons found in the stratigraphic equivalent of the Lance Pool, defined as the interval correlative to that shown on the Schlumberger Phasor Induction –SFL with Linear Correlation Log run on December 4, 1994 in the Stud Horse Butte No. 13-27 well located in the southwest quarter of the southwest quarter of Section 27, Township 29 North, Range 108 West, 6th P.M., Sublette County, Wyoming, which is from a depth of 7,975 feet (equivalent to a subsea -695 feet) to a bottom depth of 12,400 feet (-5,120 feet, subsea), as defined by the Wyoming Oil & Gas Conservation Commission in Cause No. 1, Order No. 1, Docket No. 84-2003 dated April 25, 2003, but excepting and excluding any right, title or interest in and to those liquid hydrocarbons that are separated from the gas at a central delivery point.

b.   The rights in and to the oil and gas lease described in Part III of the attached Exhibit A (“Lease”), insofar and only insofar the Lease applies to the Property, but excepting and excluding any right, title or interest in and to those liquid hydrocarbons that are separated from the gas at a central delivery point.

c.   The interests in and to the personal property and fixtures associated with all production wells on the Property, including without limitation the following: tubing, casing and other equipment in the wellbore, and wellhead equipment.

d.   All rights under the Gathering Agreement and Processing Agreement, insofar as they relate to the properties and interests described in paragraphs (a) through (c) above and are assigned to Assignee pursuant to the Letters of Attornment attached to the Carry and Earning Agreement.

Page 1 of 6

Carry and Earning Agreement – Exhibit B-2

e.   All surface and subsurface rights incident or appurtenant to the to the properties and interests described in paragraphs (a) through (c) above, and all of Assignor’s right, title and interest in and to all easements, rights-of-way, permits, licenses, servitudes or other similar interests affecting the properties and interests described in paragraphs (a) through (c) above insofar as they are necessary for the production of gas from the Property.

f.   The right to use the Assets insofar as is necessary for the production, gathering and processing of gas produced from the Property.

Assignor and Assignee further agree as follows:

1.   This Assignment is made and accepted subject to, and Assignee assumes the Permitted Encumbrances to which the Lease may be subject to, to the extent the Permitted Encumbrances cover and affect the Assigned Interests.

2.   Assignee accepts the Assigned Interests subject to all of the express and implied covenants and obligations of the Lease, insofar as they relate to the Assigned Interests.  Furthermore, Assignee accepts the Assigned Interests subject to the terms and conditions of all existing valid orders, rules, regulations and ordinances of federal, state and other governmental agencies if any, which cover and affect the Assigned Interests.

3.   Assignor warrants title as against all parties claiming an interest in the Assigned Interests by, through or under Assignor.  This Assignment is made with full substitution and subrogation of Assignee in and to all covenants and warranties made or given by others before the Effective Date.

4.   This Assignment is made in accordance with, and is subject to all the terms, provisions, and conditions of that certain Carry and Earning Agreement dated and effective as of May 1, 2011, by and between Assignor and Assignee (“Carry and Earning Agreement”) which is incorporated by this reference the same as though fully set out in this Assignment.  Capitalized terms not otherwise defined in this Assignment shall have the meanings provided in the Carry and Earning Agreement.  However, this Assignment is neither intended as, nor shall it be deemed to accomplish, a merger of the terms and provisions directly set out in this Assignment and the terms and provisions of said Carry and Earning Agreement.  Should there be any conflict between this Assignment and the Carry and Earning Agreement, the terms and conditions set out in the Carry and Earning Agreement shall prevail.  This Assignment is subject to the terms of the [***].

5.   This Assignment is made in accordance with and is subject to that certain unrecorded Operating Agreement dated effective May 1, 2011 and attached to the Carry and Earning Agreement as Exhibit C.   Should there be any conflict between this Assignment and the foregoing Operating Agreement, the terms and conditions set out in this Assignment shall prevail.

Page 2 of 6

Carry and Earning Agreement – Exhibit B-2

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

6.   The Assigned Interests do not include, and Assignor does not intend to assign and Assignee does not intend to receive, any interest in the following to the extent that such items do not directly relate to the operation of, and production of gas from, the Property:  minerals, surface interests and any other interests of a similar nature, contracts, agreements, licenses, and servitudes,  easements,  surface use and right-of-way agreements, all other property and equipment not directly used in connection with the operation of, and production from, the Property and any and all rights not expressly in this Assignment conveyed as part of the Assigned Interests

7.   The Parties stipulate that as of each date set forth in Part IV of the attached Exhibit A, Assignee and Assignor, respectively, own the cumulative working interest and Net Revenue Interest set forth in Part IV of the attached Exhibit A in the Lease, insofar as the Lease pertains to the Property, and the production attributable thereto.

8.   The references in this Assignment to liens, encumbrances, burdens, defects, agreements and other matters shall not be deemed to recognize or create any rights in third parties or merge with, modify, or limit the rights of Assignor or Assignee, as between themselves.

9.   This Assignment may be executed by signing an original or a counterpart of an original. If this Assignment is executed in counterparts, all counterparts taken together shall have the same effect as if Assignor and Assignee had signed the same instrument.

[Remainder of this page left intentionally blank]

Page 3 of 6

Carry and Earning Agreement – Exhibit B-2

TO HAVE AND TO HOLD the assigned interest unto Assignee and its successors and assigns, subject to all the express and implied covenants and obligations of the Leases and this Assignment.

EXECUTED this ___ day of ____20__, but effective as of the Effective Date(s) set forth in Part II of the attached Exhibit A.

ENCANA OIL & GAS (USA) INC.

By:_________________________________________

Constance D. Heath, Attorney in Fact

ACKNOWLEDGEMENT

STATE OF COLORADO                                                      §

§

CITY AND COUNTY OF DENVER                                                                §

BEFORE ME, the undersigned authority, on this day personally appeared Constance D. Heath, Attorney-in-Fact for ENCANA OIL & GAS (USA) INC., known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that she executed the same for the purposes and consideration therein expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this _________ day of __________ 20__.

MY COMMISSION EXPIRES:

______________________________                                                                

Notary Public in and for the State of Colorado

Page 4 of 6

Carry and Earning Agreement – Exhibit B-2

NORTHWEST NATURAL GAS COMPANY

By: ________________________________________

Name/Title:

ACKNOWLEDGEMENT

STATE OF §

 §

COUNTY OF §

BEFORE ME, the undersigned authority, on this day personally appeared _____________________, as ________________ for NORTHWEST NATURAL GAS COMPANY known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same for the purposes and consideration therein expressed and in the capacity therein stated.

__________ 20__.

MY COMMISSION EXPIRES:

______________________________                                                                           

Notary Public

Page 5 of 6

Carry and Earning Agreement – Exhibit B-2

A.A.P.L. FORM 610 - 1989

MODEL FORM OPERATING AGREEMENT

Exhibit “C”

OPERATING AGREEMENT

DATED

				May 1	,	2011	,
year
OPERATOR	Encana Oil & Gas (USA) Inc.
CONTRACT AREA		Township 29, Range 108 West, 6th P.M.
Sections 9, 10, 14, 15, 16, 17, 32, 33, 34: All
Section 11: SW/4
COUNTY OR PARISH OF			Sublette					, STATE OF	Wyoming

COPYRIGHT 1989 – ALL RIGHTS RESERVED

AMERICAN ASSOCIATION OF PETROLEUM

LANDMEN, 4100 FOSSIL CREEK BLVD.

FORT WORTH, TEXAS, 76137, APPROVED FORM.

A.A.P.L. NO. 610 – 1989

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

TABLE OF CONTENTS

Article                                                                  TitlePage

       I.DEFINITIONS 1

       II.EXHIBITS 1

       III.INTERESTS OF PARTIES 2

A.  OIL AND GAS INTERESTS: 2

B.  INTERESTS OF PARTIES IN COSTS AND PRODUCTION: 2

C.  SUBSEQUENTLY CREATED INTERESTS: 2

       IV.TITLES 2

A.  TITLE EXAMINATION: 2

B.  LOSS OR FAILURE OF TITLE: 3

1.  Failure of Title 3

2.  Loss by Non-Payment or Erroneous Payment of Amount Due 3

3.  Other Losses 3

4.  Curing Title 3

       V.OPERATOR 4

A.  DESIGNATION AND RESPONSIBILITIES OF OPERATOR: 4

B.  RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR: 4

1.  Resignation or Removal of Operator 4

2.  Selection of Successor Operator 4

3.  Effect of Bankruptcy 4

C.  EMPLOYEES AND CONTRACTORS: 4

D.  RIGHTS AND DUTIES OF OPERATOR: 4

1.  Competitive Rates and Use of Affiliates 4

2.  Discharge of Joint Account Obligations 4

3.  Protection from Liens 4

4.  Custody of Funds 5

5.  Access to Contract Area and Records 5

6.  Filing and Furnishing Governmental Reports 5

7.  Drilling and Testing Operations 5

8.  Cost Estimates 5

9.  Insurance 5

       VI.DRILLING AND DEVELOPMENT 5

A.  INITIAL WELL: 5

B.  SUBSEQUENT OPERATIONS: 5

1.  Proposed Operations 5

2.  Operations by Less Than All Parties 6

3.  Stand-By Costs 7

4.  Deepening 8

5.  Sidetracking 8

6.  Order of Preference of Operations 8

7.  Conformity to Spacing Pattern 9

8.  Paying Wells 9

C.  COMPLETION OF WELLS; REWORKING AND PLUGGING BACK: 9

1.  Completion 9

2.  Rework, Recomplete or Plug Back 9

D.  OTHER OPERATIONS: 9

E.  ABANDONMENT OF WELLS: 9

1.  Abandonment of Dry Holes 9

2.  Abandonment of Wells That Have Produced 10

3.  Abandonment of Non-Consent Operations 10

F.  TERMINATION OF OPERATIONS: 10

G.  TAKING PRODUCTION IN KIND: 10

(Option 1) Gas Balancing Agreement 10

(Option 2) No Gas Balancing Agreement 11

VII.          EXPENDITURES AND LIABILITY OF PARTIES 11

A.  LIABILITY OF PARTIES: 11

B.  LIENS AND SECURITY INTERESTS: 12

C.  ADVANCES: 12

D.  DEFAULTS AND REMEDIES: 12

1.  Suspension of Rights 13

2.  Suit for Damages 13

3.  Deemed Non-Consent 13

4.  Advance Payment 13

5.  Costs and Attorneys’ Fees 13

E.  RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES:13

F.  TAXES: 13

VIII.          ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST 14

A.  SURRENDER OF LEASES: 14

B.  RENEWAL OR EXTENSION OF LEASES: 14

C.  ACREAGE OR CASH CONTRIBUTIONS: 14

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

TABLE OF CONTENTS

D.     ASSIGNMENT; MAINTENANCE OF UNIFORM INTEREST: 15

E.     WAIVER OF RIGHTS TO PARTITION: 15

F.     PREFERENTIAL RIGHT TO PURCHASE: 15

       IX.INTERNAL REVENUE CODE ELECTION 15

       X.CLAIMS AND LAWSUITS 15

       XI.FORCE MAJEURE 16

XII.          NOTICES 16

XIII.          TERM OF AGREEMENT 16

XIV.          COMPLIANCE WITH LAWS AND REGULATIONS  16

A.     LAWS, REGULATIONS AND ORDERS: 16

B.     GOVERNING LAW: 16

C.     REGULATORY AGENCIES: 16

XV.          MISCELLANEOUS 17

A.     EXECUTION: 17

B.     SUCCESSORS AND ASSIGNS: 17

C.     COUNTERPARTS: 17

D.     SEVERABILITY 17

XVI.          OTHER PROVISIONS 17

ii.

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

OPERATING AGREEMENT

THIS AGREEMENT, entered into by and between     Encana Oil & Gas (USA) Inc. ,

hereinafter designated and referred to as "Operator," and the signatory party or parties other than Operator, sometimes

hereinafter referred to individually as "Non-Operator," and collectively as "Non-Operators."

WITNESSETH:

WHEREAS, the parties to this agreement are owners of Oil and Gas Leases and/or Oil and Gas Interests in the land

identified in Exhibit "A," and the parties hereto have reached an agreement to explore and develop these Leases and/or Oil

and Gas Interests for the production of Oil and Gas to the extent and as hereinafter provided,

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.

DEFINITIONS

As used in this agreement, the following words and terms shall have the meanings here ascribed to them:

A.  The term "AFE" shall mean an Authority for Expenditure prepared by a party to this agreement for the purpose of

estimating the costs to be incurred in conducting an operation hereunder.

B.  The term "Completion" or "Complete" shall mean a single operation intended to complete a well as a producer of Oil

and Gas in one or more Zones, including, but not limited to, the setting of production casing, perforating, well stimulation

and production testing conducted in such operation.

C.  The term "Contract Area" shall mean all of the lands, Oil and Gas Leases and/or Oil and Gas Interests intended to be

developed and operated for Oil and Gas purposes under this agreement.  Such lands, Oil and Gas Leases and Oil and Gas

Interests are described in Exhibit "A."

D.  The term "Deepen" shall mean a single operation whereby a well is drilled to an objective Zone below the deepest

Zone in which the well was previously drilled, or below the Deepest Zone proposed in the associated AFE, whichever is the

lesser.

E.  The terms "Drilling Party" and "Consenting Party" shall mean a party who agrees to join in and pay its share of the

cost of any operation conducted under the provisions of this agreement.

        wells

F.  The term "Drilling Unit" shall mean the area fixed for the drilling of one well  / by order or rule of any state or federal

body having authority.  If a Drilling Unit is not fixed by any such rule or order, a Drilling Unit shall be the drilling unit as

established by the pattern of drilling in the Contract Area unless fixed by express agreement of the Drilling Parties.

G.  The term "Drillsite" shall mean the Oil and Gas Lease or Oil and Gas Interest on which a proposed well is to be

located.

H.  The term "Initial Well" shall mean the well required to be drilled by the parties hereto as provided in Article VI.A.

I.  The term "Non-Consent Well" shall mean a well in which less than all parties have conducted an operation as

provided in Article VI.B.2.

J.  The terms "Non-Drilling Party" and "Non-Consenting Party" shall mean a party who elects not to participate in a

proposed operation.

K.  The term "Oil and Gas" shall mean oil, gas, casinghead gas, gas condensate, and/or all other liquid or gaseous

hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is

specifically stated.

L.  The term "Oil and Gas Interests" or "Interests" shall mean unleased fee and mineral interests in Oil and Gas in tracts

of land lying within the Contract Area which are owned by parties to this agreement.

M.  The terms "Oil and Gas Lease," "Lease" and "Leasehold" shall mean the oil and gas leases or interests therein

covering tracts of land lying within the Contract Area which are owned by the parties to this agreement.

N.  The term "Plug Back" shall mean a single operation whereby a deeper Zone is abandoned in order to attempt a

Completion in a shallower Zone.

O.  The term "Recompletion" or "Recomplete" shall mean an operation whereby a Completion in one Zone is abandoned

in order to attempt a Completion in a different Zone within the existing wellbore.

P.  The term "Rework" shall mean an operation conducted in the wellbore of a well after it is Completed to secure,

restore, or improve production in a Zone which is currently open to production in the wellbore.  Such operations include, but

are not limited to, well stimulation operations but exclude any routine repair or maintenance work or drilling, Sidetracking,

Deepening, Completing, Recompleting, or Plugging Back of a well.

Q.  The term "Sidetrack" shall mean the directional control and intentional deviation of a well from vertical so as to

change the bottom hole location unless done to straighten the hole or drill around junk in the hole to overcome other

mechanical difficulties.

R.  The term "Zone" shall mean a stratum of earth containing or thought to contain a common accumulation of Oil and

Gas separately producible from any other common accumulation of Oil and Gas.

Unless the context otherwise clearly indicates, words used in the singular include the plural, the word "person" includes

natural and artificial persons, the plural includes the singular, and any gender includes the masculine, feminine, and neuter.

ARTICLE II.

EXHIBITS

The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof:

X       A.              Exhibit "A," shall include the following information:

(1) Description of lands subject to this agreement,

(2) Restrictions, if any, as to depths, formations, or substances,

(3) Parties to agreement with addresses and telephone numbers for notice purposes,

(4) Percentages or fractional interests of parties to this agreement,

(5) Oil and Gas Leases and/or Oil and Gas Interests subject to this agreement,

(6) Burdens on production.

B.     Exhibit "B," Form of Lease.

X      C.     Exhibit "C," Accounting Procedure.

X      D.     Exhibit "D," Insurance.

X      E.     Exhibit "E," Gas Balancing Agreement.

     X          F.     Exhibit "F," Non-Discrimination and Certification of Non-Segregated Facilities.

X      G.     Exhibit "G," Tax Partnership.

X      H.     Other: Exhibit “H,” Marketing Agreement; Exhibit “I.” Memorandum; Exhibit “J.” Financing Statement.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

If any provision of any exhibit, except Exhibits "E," "F" and "G," is inconsistent with any provision contained in

the body of this agreement, the provisions in the body of this agreement shall prevail.

ARTICLE III.

INTERESTS OF PARTIES

A.  Oil and Gas Interests:

If any party owns an Oil and Gas Interest in the Contract Area, that Interest shall be treated for all purposes of this

agreement and during the term hereof as if it were covered by the form of Oil and Gas Lease attached hereto as Exhibit "B,"

and the owner thereof shall be deemed to own both royalty interest in such lease and the interest of the lessee thereunder.

B.  Interests of Parties in Costs and Production:

Unless changed by other provisions, all costs and liabilities incurred in operations under this agreement shall be borne

and paid, and all equipment and materials acquired in operations on the Contract Area shall be owned, by the parties as their

interests are set forth in Exhibit "A."  In the same manner, the parties shall also own all production of Oil and Gas from the

Contract Area subject, however, to the payment of royalties and other burdens on production as described hereafter.

Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas Interest on which royalty or other

burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or

cause to be paid or delivered, all burdens on its share of the production from the Contract Area up to, but not in excess of,

burdens shown on Exhibit “A” and shall indemnify, defend and hold the other parties free from any liability therefor.

Except as otherwise expressly provided in this agreement, if any party has contributed hereto any Lease or Interest which is

burdened with any royalty, overriding royalty, production payment or other burden on production in excess of the amounts

stipulated above, such party so burdened shall assume and alone bear all such excess obligations and shall indemnify, defend

and hold the other parties hereto harmless from any and all claims attributable to such excess burden.  However, so long as

the Drilling Unit for the productive Zone(s) is identical with the Contract Area, each party shall pay or deliver, or cause to

be paid or delivered, all burdens on production from the Contract Area due under the terms of the Oil and Gas Lease(s)

which such party has contributed to this agreement, and shall indemnify, defend and hold the other parties free from any

liability therefor.

No party shall ever be responsible, on a price basis higher than the price received by such party, to any other party's

lessor or royalty owner, and if such other party's lessor or royalty owner should demand and receive settlement on a higher

price basis, the party contributing the affected Lease shall bear the additional royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment or cross-assignment of interests covered hereby,

and in the event two or more parties contribute to this agreement jointly owned Leases, the parties' undivided interests in

said Leaseholds shall be deemed separate leasehold interests for the purposes of this agreement.

C.  Subsequently Created Interests:

If any party has contributed hereto a Lease or Interest that is burdened with an assignment of production given as security

for the payment of money, or if, after the date of this agreement, any party creates an overriding royalty, production

payment, net profits interest, assignment of production or other burden payable out of production attributable to its working

interest hereunder, such burden shall be deemed a "Subsequently Created Interest."  Further, if any party has contributed

hereto a Lease or Interest burdened with an overriding royalty, production payment, net profits interests, or other burden

in excess of the burdens

payable out of production created prior to the date of this agreement, / and such burden is not shown on Exhibit "A," such

burden also shall be deemed a Subsequently Created Interest to the extent such burden causes the burdens on such party's

Lease or Interest to exceed the amount stipulated in Article III.B. above.

The party whose interest is burdened with the Subsequently Created Interest (the "Burdened Party") shall assume and

alone bear, pay and discharge the Subsequently Created Interest and shall indemnify, defend and hold harmless the other

parties from and against any liability therefor.  Further, if the Burdened Party fails to pay, when due, its share of expenses

chargeable hereunder, all provisions of Article VII.B. shall be enforceable against the Subsequently Created Interest in the

same manner as they are enforceable against the working interest of the Burdened Party.  If the Burdened Party is required

under this agreement to assign or relinquish to any other party, or parties, all or a portion of its working interest and/or the

production attributable thereto, said other party, or parties, shall receive said assignment and/or production free and clear of

said Subsequently Created Interest, and the Burdened Party shall indemnify, defend and hold harmless said other party, or

parties, from any and all claims and demands for payment asserted by owners of the Subsequently Created Interest.

ARTICLE IV.

TITLES

A.  Title Examination:

Title examination shall be made on the Drillsite of any proposed well prior to commencement of drilling operations and,

      If

if / a majority in interest of the Drilling Parties so request or Operator so elects, title examination shall be made on the entire

Drilling Unit, or maximum anticipated Drilling Unit, of the well.   The opinion will include the ownership of the working

interest, minerals, royalty, overriding royalty and production payments under the applicable Leases.   Each party contributing

Leases and/or Oil and Gas Interests to be included in the Drillsite or Drilling Unit, if appropriate, shall furnish to Operator

all abstracts (including federal lease status reports), title opinions, title papers and curative material in its possession free of

charge.  All such information not in the possession of or made available to Operator by the parties, but necessary for the

examination of the title, shall be obtained by Operator.  Operator shall cause title to be examined by attorneys on its staff or

      Upon request by Drilling Party                                                                                 the

by outside attorneys. / Copies of all title opinions shall be furnished to each / Drilling Party.  Costs incurred by Operator in

procuring abstracts, fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in royalty

opinions and division order title opinions) and other direct charges as provided in Exhibit "C" shall be borne by the Drilling

Parties in the proportion that the interest of each Drilling Party bears to the total interest of all Drilling Parties as such

interests appear in Exhibit "A."  Operator shall make no charge for services rendered by its staff attorneys or other personnel

in the performance of the above functions.

Each party shall be responsible for securing curative matter and pooling amendments or agreements required in

connection with Leases or Oil and Gas Interests contributed by such party.  Operator shall be responsible for the preparation

and recording of pooling designations or declarations and communitization agreements as well as the conduct of hearings

before governmental agencies for the securing of spacing or pooling orders or any other orders necessary or appropriate to

the conduct of operations hereunder.  This shall not prevent any party from appearing on its own behalf at such hearings.

Costs incurred by Operator, including fees paid to outside attorneys, which are associated with hearings before governmental

agencies, and which costs are necessary and proper for the activities contemplated under this agreement, shall be direct

charges to the joint account and shall not be covered by the administrative overhead charges as provided in Exhibit "C."

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above

functions.

No well shall be drilled on the Contract Area until after (1) the title to the Drillsite or Drilling Unit, if appropriate, has

been examined as above provided, and (2) the title has been approved by the examining attorney or title has been accepted by

all of the Drilling Parties in such well.

B. Loss or Failure of Title:

1.  Failure of Title: Should any Oil and Gas Interest or Oil and Gas Lease be lost through failure of title, which results in a

reduction of interest from that shown on Exhibit "A," the party credited with contributing the affected Lease or Interest

(including, if applicable, a successor in interest to such party) shall have ninety (90) days from final determination of title

failure to acquire a new lease or other instrument curing the entirety of the title failure, which acquisition will not be subject

to Article VIII.B., and failing to do so, this agreement, nevertheless, shall continue in force as to all remaining Oil and Gas

Leases and Interests; and,

(a) The party credited with contributing the Oil and Gas Lease or Interest affected by the title failure (including, if

applicable, a successor in interest to such party) shall bear alone the entire loss and it shall not be entitled to recover from

Operator or the other parties any development or operating costs which it may have previously paid or incurred, but there

shall be no additional liability on its part to the other parties hereto by reason of such title failure;

(b) There shall be no retroactive adjustment of expenses incurred or revenues received from the operation of the

Lease or Interest which has failed, but the interests of the parties contained on Exhibit "A" shall be revised on an acreage

basis, as of the time it is determined finally that title failure has occurred, so that the interest of the party whose Lease or

Interest is affected by the title failure will thereafter be reduced in the Contract Area by the amount of the Lease or Interest failed;

(c) If the proportionate interest of the other parties hereto in any producing well previously drilled on the Contract

Area is increased by reason of the title failure, the party who bore the costs incurred in connection with such well attributable

to the Lease or Interest which has failed shall receive the proceeds attributable to the increase in such interest (less costs and

burdens attributable thereto) until it has been reimbursed for unrecovered costs paid by it in connection with such well

attributable to such failed Lease or Interest;

(d) Should any person not a party to this agreement, who is determined to be the owner of any Lease or Interest

which has failed, pay in any manner any part of the cost of operation, development, or equipment, such amount shall be paid

to the party or parties who bore the costs which are so refunded;

(e) Any liability to account to a person not a party to this agreement for prior production of Oil and Gas which arises

by reason of title failure shall be borne severally by each party (including a predecessor to a current party) who received

production for which such accounting is required based on the amount of such production received, and each such party shall

severally indemnify, defend and hold harmless all other parties hereto for any such liability to account;

(f) No charge shall be made to the joint account for legal expenses, fees or salaries in connection with the defense of

the Lease or Interest claimed to have failed, but if the party contributing such Lease or Interest hereto elects to defend its title

it shall bear all expenses in connection therewith; and

(g) If any party is given credit on Exhibit "A" to a Lease or Interest which is limited solely to ownership of an

interest in the wellbore of any well or wells and the production therefrom, such party's absence of interest in the remainder

of the Contract Area shall be considered a Failure of Title as to such remaining Contract Area unless that absence of interest

is reflected on Exhibit "A."

2.  Loss by Non-Payment or Erroneous Payment of Amount Due: If, through mistake or oversight, any rental, shut-in well

payment, minimum royalty or royalty payment, or other payment necessary to maintain all or a portion of an Oil and Gas

Lease or interest is not paid or is erroneously paid, and as a result a Lease or Interest terminates, there shall be no monetary

liability against the party who failed to make such payment.  Unless the party who failed to make the required payment

secures a new Lease or Interest covering the same interest within ninety (90) days from the discovery of the failure to make

proper payment, which acquisition will not be subject to Article VIII.B., the interests of the parties reflected on Exhibit "A"

shall be revised on an acreage basis, effective as of the date of termination of the Lease or Interest involved, and the party

who failed to make proper payment will no longer be credited with an interest in the Contract Area on account of ownership

of the Lease or Interest which has terminated.  If the party who failed to make the required payment shall not have been fully

reimbursed, at the time of the loss, from the proceeds of the sale of Oil and Gas attributable to the lost Lease or Interest,

calculated on an acreage basis, for the development and operating costs previously paid on account of such Lease or Interest,

it shall be reimbursed for unrecovered actual costs previously paid by it (but not for its share of the cost of any dry hole

previously drilled or wells previously abandoned) from so much of the following as is necessary to effect reimbursement:

(a) Proceeds of Oil and Gas produced prior to termination of the Lease or Interest, less operating expenses and lease

burdens chargeable hereunder to the person who failed to make payment, previously accrued to the credit of the lost Lease or

Interest, on an acreage basis, up to the amount of unrecovered costs;

(b) Proceeds of Oil and Gas, less operating expenses and lease burdens chargeable hereunder to the person who failed

to make payment, up to the amount of unrecovered costs attributable to that portion of Oil and Gas thereafter produced and

marketed (excluding production from any wells thereafter drilled) which, in the absence of such Lease or Interest termination,

would be attributable to the lost Lease or Interest on an acreage basis and which as a result of such Lease or Interest

termination is credited to other parties, the proceeds of said portion of the Oil and Gas to be contributed by the other parties

in proportion to their respective interests reflected on Exhibit "A"; and,

(c) Any monies, up to the amount of unrecovered costs, that may be paid by any party who is, or becomes, the owner

of the Lease or Interest lost, for the privilege of participating in the Contract Area or becoming a party to this agreement.

3. Other Losses: All losses of Leases or Interests committed to this agreement, other than those set forth in Articles

IV.B.1. and IV.B.2. above, shall be joint losses and shall be borne by all parties in proportion to their interests shown on

Exhibit "A."  This shall include but not be limited to the loss of any Lease or Interest through failure to develop or because

express or implied covenants have not been performed (other than performance which requires only the payment of money),

and the loss of any Lease by expiration at the end of its primary term if it is not renewed or extended.  There shall be no

readjustment of interests in the remaining portion of the Contract Area on account of any joint loss.

4. Curing Title: In the event of a Failure of Title under Article IV.B.1. or a loss of title under Article IV.B.2. above, any

Lease or Interest acquired by any party hereto (other than the party whose interest has failed or was lost) during the ninety

(90) day period provided by Article IV.B.1. and Article IV.B.2. above covering all or a portion of the interest that has failed

or was lost shall be offered at cost to the party whose interest has failed or was lost, and the provisions of Article VIII.B.

shall not apply to such acquisition.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

ARTICLE V.

OPERATOR

A.  Designation and Responsibilities of Operator:

Encana Oil & Gas (USA) Inc.                                                            shall be the Operator of the Contract Area, and shall conduct

and direct and have full control of all operations on the Contract Area as permitted and required by, and within the limits of

this agreement.  In its performance of services hereunder for the Non-Operators, Operator shall be an independent contractor

not subject to the control or direction of the Non-Operators except as to the type of operation to be undertaken in accordance

with the election procedures contained in this agreement.  Operator shall not be deemed, or hold itself out as, the agent of the

Non-Operators with authority to bind them to any obligation or liability assumed or incurred by Operator as to any third

party.  Operator shall conduct its activities under this agreement as a reasonable prudent operator, in a good and workmanlike

manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and

regulation, but in no event shall it have any liability as Operator to the other parties for losses sustained or liabilities incurred

except such as may result from gross negligence or willful misconduct.

B. Resignation or Removal of Operator and Selection of Successor:

1. Resignation or Removal of Operator: Operator may resign at any time by giving written notice thereof to Non-Operators.

If Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of

serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators, except the selection of a

successor.  Operator may be removed only for good cause by the affirmative vote of Non-Operators owning a majority interest

based on ownership as shown on Exhibit "A" remaining after excluding the voting interest of Operator; such vote shall not be

deemed effective until a written notice has been delivered to the Operator by a Non-Operator detailing the alleged default and

Operator has failed to cure the default within thirty (30) days from its receipt of the notice or, if the default concerns an

operation then being conducted, within forty-eight (48) hours of its receipt of the notice.  For purposes hereof, "good cause" shall

mean not only gross negligence or willful misconduct but also the material breach of or inability to meet the standards of

operation contained in Article V.A. or material failure or inability to perform its obligations under this agreement.

Subject to Article VII.D.1., such resignation or removal shall not become effective until 7:00 o'clock A.M. on the first

day of the calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator

or action by the Non-Operators to remove Operator, unless a successor Operator has been selected and assumes the duties of

Operator at an earlier date. Operator, after effective date of resignation or removal, shall be bound by the terms hereof as a

Non-Operator.  A change of a corporate name or structure of Operator or transfer of Operator's interest to any single

subsidiary, parent or successor corporation shall not be the basis for removal of Operator.

2.  Selection of Successor Operator: Upon the resignation or removal of Operator under any provision of this agreement, a

successor Operator shall be selected by the parties.  The successor Operator shall be selected from the parties owning an

interest in the Contract Area at the time such successor Operator is selected.  The successor Operator shall be selected by the

affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit "A";

provided, however, if an Operator which has been removed or is deemed to have resigned fails to vote or votes only to

succeed itself, the successor Operator shall be selected by the affirmative vote of the party or parties owning a majority

interest based on ownership as shown on Exhibit "A" remaining after excluding the voting interest of the Operator that was

removed or resigned.  The former Operator shall promptly deliver to the successor Operator all records and data relating to

the operations conducted by the former Operator to the extent such records and data are not already in the possession of the

successor operator.  Any cost of obtaining or copying the former Operator's records and data shall be charged to the joint

account.

3.  Effect of Bankruptcy: If Operator becomes insolvent, bankrupt or is placed in receivership, it shall be deemed to have

resigned without any action by Non-Operators, except the selection of a successor.  If a petition for relief under the federal

bankruptcy laws is filed by or against Operator, and the removal of Operator is prevented by the federal bankruptcy court, all

Non-Operators and Operator shall comprise an interim operating committee to serve until Operator has elected to reject or

assume this agreement pursuant to the Bankruptcy Code, and an election to reject this agreement by Operator as a debtor in

possession, or by a trustee in bankruptcy, shall be deemed a resignation as Operator without any action by Non-Operators,

except the selection of a successor.  During the period of time the operating committee controls operations, all actions shall

require the approval of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit "A."  In

the event there are only two (2) parties to this agreement, during the period of time the operating committee controls

operations, a third party acceptable to Operator, Non-Operator and the federal bankruptcy court shall be selected as a

member of the operating committee, and all actions shall require the approval of two (2) members of the operating

committee without regard for their interest in the Contract Area based on Exhibit "A."

C.  Employees and Contractors:

The number of employees or contractors used by Operator in conducting operations hereunder, their selection, and the

hours of labor and the compensation for services performed shall be determined Operator, and all such employees or

contractors shall be the employees or contractors of Operator.

D.  Rights and Duties of Operator:

1. Competitive Rates and Use of Affiliates: All wells drilled on the Contract Area shall be drilled on a competitive

contract basis at the usual rates prevailing in the area.  If it so desires, Operator may employ its own tools and equipment in

the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges

shall be agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by

Operator under the same terms and conditions as are customary and usual in the area in contracts of independent contractors

who are doing work of a similar nature.  All work performed or materials supplied by affiliates or related parties of Operator

shall be performed or supplied at competitive rates, pursuant to written agreement, and in accordance with customs and

standards prevailing in  the industry.

2. Discharge of Joint Account Obligations: Except as herein otherwise specifically provided, Operator shall promptly pay

and discharge expenses incurred in the development and operation of the Contract Area pursuant to this agreement and shall

charge each of the parties hereto with their respective proportionate shares upon the expense basis provided in Exhibit "C."

Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits

made and received.

3. Protection from Liens: Operator shall pay, or cause to be paid, as and when they become due and payable, all accounts

of contractors and suppliers and wages and salaries for services rendered or performed, and for materials supplied on, to or in

respect of the Contract Area or any operations for the joint account thereof, and shall keep the Contract Area free from

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

liens and encumbrances resulting therefrom except for those resulting from a bona fide dispute as to services rendered or

materials supplied.

4. Custody of Funds: Operator shall hold for the account of the Non-Operators any funds of the Non-Operators advanced

or paid to the Operator, either for the conduct of operations hereunder or as a result of the sale of production from the

Contract Area, and such funds shall remain the funds of the Non-Operators on whose account they are advanced or paid until

used for their intended purpose or otherwise delivered to the Non-Operators or applied toward the payment of debts as

provided in Article VII.B.  Nothing in this paragraph shall be construed to establish a fiduciary relationship between Operator

and Non-Operators for any purpose other than to account for Non-Operator funds as herein specifically provided.  Nothing in

this paragraph shall require the maintenance by Operator of separate accounts for the funds of Non-Operators unless the

parties otherwise specifically agree.

5. Access to Contract Area and Records: Operator shall, except as otherwise provided herein, permit each Non-Operator

or its duly authorized representative, at the Non-Operator's sole risk and cost, full and free access at all reasonable times to

all operations of every kind and character being conducted for the joint account on the Contract Area and to the records of

operations conducted thereon or production therefrom, including Operator's books and records relating thereto.  Such access

rights shall not be exercised in a manner interfering with Operator's conduct of an operation hereunder and shall not obligate

Operator to furnish any geologic or geophysical data of an interpretive nature unless the cost of preparation of such

interpretive data was charged to the joint account.  Operator will furnish to each Non-Operator upon request copies of any

and all reports and information obtained by Operator in connection with production and related items, including, without

limitation, meter and chart reports, production purchaser statements, run tickets and monthly gauge reports, but excluding

purchase contracts and pricing information to the extent not applicable to the production of the Non-Operator seeking the

information.  Any audit of Operator's records relating to amounts expended and the appropriateness of such expenditures

shall be conducted in accordance with the audit protocol specified in Exhibit "C."

6. Filing and Furnishing Governmental Reports: Operator will file, and upon written request promptly furnish copies to

each requesting Non-Operator not in default of its payment obligations, all operational notices, reports or applications

required to be filed by local, State, Federal or Indian agencies or authorities having jurisdiction over operations hereunder.

Each Non-Operator shall provide to Operator on a timely basis all information necessary to Operator to make such filings.

Completed, Reworked, Recompleted, Sidetracked or Plugged Back

7. Drilling and Testing Operations: The following provisions shall apply to each well drilled / hereunder, including but not

limited to the Initial Well:

(a) Operator will promptly advise Non-Operators of the date on which the well is spudded, or the date on which

drilling operations are commenced.

(b) Operator will send to Non-Operators such reports, test results and notices regarding the progress of operations on  the well

as the Non-Operators shall reasonably request, including, but not limited to, daily drilling reports, completion reports, and well logs.

proposed under Proposed Operations as provided under Article VI.B.1 that are

(c) Operator shall adequately test all Zones / encountered which may reasonably be expected to be capable of producing

Oil and Gas in paying quantities as a result of examination of the electric log or any other logs or cores or tests conducted

hereunder.

8. Cost Estimates: Upon request of any Consenting Party, Operator shall furnish estimates of current and cumulative costs

incurred for the joint account at reasonable intervals during the conduct of any operation pursuant to this agreement.

Operator shall not be held liable for errors in such estimates so long as the estimates are made in good faith.

9. Insurance: At all times while operations are conducted hereunder, Operator shall comply with the workers

compensation law of the state where the operations are being conducted; provided, however, that Operator may be a self-

insurer for liability under said compensation laws in which event the only charge that shall be made to the joint account shall

be as provided in Exhibit "C."  Operator shall also carry or provide insurance for the benefit of the joint account of the parties

as outlined in Exhibit "D" attached hereto and made a part hereof.  Operator shall require all contractors engaged in work on

or for the Contract Area to comply with the workers compensation law of the state where the operations are being conducted

and to maintain such other insurance as Operator may require.

In the event automobile liability insurance is specified in said Exhibit "D," or subsequently receives the approval of the

parties, no direct charge shall be made by Operator for premiums paid for such insurance for Operator's automotive

equipment.

ARTICLE VI.

DRILLING AND DEVELOPMENT

A.  Initial Well:

On or before the                                                         day of,, Operator shall commence the drilling of the Initial

Well at the following location:

and shall thereafter continue the drilling of the well with due diligence to

The drilling of the Initial Well and the participation therein by all parties is obligatory, subject to Article VI.C.1. as to participation

in Completion operations and Article VI.F. as to termination of operations and Article XI as to occurrence of force majeure.

B.  Subsequent Operations:

1.  Proposed Operations: If any party hereto should desire to drill any well on the Contract Area other than the Initial Well, or

if any party should desire to Rework, Sidetrack, Deepen, Recomplete or Plug Back a dry hole or a well no longer capable of

producing in paying quantities in which such party has not otherwise relinquished its interest in the proposed objective Zone under

this agreement, the party desiring to drill, Rework, Sidetrack, Deepen, Recomplete or Plug Back such a well shall give written

notice of the proposed operation to the parties who have not otherwise relinquished their interest in such objective Zone

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

under this agreement and to all other parties in the case of a proposal for Sidetracking or Deepening, specifying the work to be

performed, the location, proposed depth, objective Zone and the estimated cost of the operation.  The parties to whom such a

notice is delivered shall have thirty (30) days after receipt of the notice within which to notify the party proposing to do the work

whether they elect to participate in the cost of the proposed operation.  If a drilling rig is on location, notice of a proposal to

Rework, Sidetrack, Recomplete, Plug Back or Deepen may be given by telephone and the response period shall be limited to forty-

eight (48) hours, exclusive of Saturday, Sunday and legal holidays.  Failure of a party to whom such notice is delivered to reply

within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation.

Any proposal by a party to conduct an operation conflicting with the operation initially proposed shall be delivered to all parties

within the time and in the manner provided in Article VI.B.6.

If all parties to whom such notice is delivered elect to participate in such a proposed operation, the parties shall be

contractually committed to participate therein provided such operations are commenced within the time period hereafter set

one-hundred twenty (120)

forth, and Operator shall, no later than ninety (90) / days after expiration of the notice period of thirty (30) days (or as

promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case

may be), actually commence the proposed operation and thereafter complete it with due diligence at the risk and expense of

the parties participating therein; provided, however, said commencement date may be extended upon written notice of same

by Operator to the other parties, for a period of up to thirty (30) additional days if, in the sole opinion of Operator, such

additional time is reasonably necessary to obtain permits from governmental authorities, surface rights (including rights-of-

way) or appropriate drilling equipment, or to complete title examination or curative matter required for title approval or

acceptance.  If the actual operation has not been commenced within the time provided (including any extension thereof as

specifically permitted herein or in the force majeure provisions of Article XI) and if any party hereto still desires to conduct

said operation, written notice proposing same must be resubmitted to the other parties in accordance herewith as if no prior

proposal had been made.  Those parties that did not participate in the drilling of a well for which a proposal to Deepen or

Sidetrack is made hereunder shall, if such parties desire to participate in the proposed Deepening or Sidetracking operation,

reimburse the Drilling Parties in accordance with Article VI.B.4. in the event of a Deepening operation and in accordance

with Article VI.B.5. in the event of a Sidetracking operation.

2.  Operations by Less Than All Parties:

(a) Determination of Participation.  If any party to whom such notice is delivered as provided in Article VI.B.1. or

VI.C.1. (Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this

Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation shall, no

one-hundred twenty (120)

later than ninety (90) / days after the expiration of the notice period of thirty (30) days (or as promptly as practicable after the

expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case may be) actually commence the

proposed operation and complete it with due diligence.  Operator shall perform all work for the account of the Consenting

Parties; provided, however, if no drilling rig or other equipment is on location, and if Operator is a Non-Consenting Party,

the Consenting Parties shall either: (i) request Operator to perform the work required by such proposed operation for the

account of the Consenting Parties, or (ii) designate one of the Consenting Parties as Operator to perform such work.  The

rights and duties granted to and imposed upon the Operator under this agreement are granted to and imposed upon the party

designated as Operator for an operation in which the original Operator is a Non-Consenting Party.  Consenting Parties, when

conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and conditions of this

agreement.

If less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the

applicable notice period, shall advise all Parties of the total interest of the parties approving such operation and its

recommendation as to whether the Consenting Parties should proceed with the operation as proposed.  Each Consenting Party,

within forty-eight (48) hours (exclusive of Saturday, Sunday, and legal holidays) after delivery of such notice, shall advise the

proposing party of its desire to (i) limit participation to such party's interest as shown on Exhibit "A" or (ii) carry only its

proportionate part (determined by dividing such party's interest in the Contract Area by the interests of all Consenting Parties in

the Contract Area) of Non-Consenting Parties' interests, or (iii) carry its proportionate part (determined as provided in (ii)) of

Non-Consenting Parties' interests together with all or a portion of its proportionate part of any Non-Consenting Parties'

interests that any Consenting Party did not elect to take.  Any interest of Non-Consenting Parties that is not carried by a

Consenting Party shall be deemed to be carried by the party proposing the operation if such party does not withdraw its

proposal.  Failure to advise the proposing party within the time required shall be deemed an election under (i). In the event a

drilling rig is on location, notice may be given by telephone, and the time permitted for such a response shall not exceed a

total of forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays).  The proposing party, at its election, may

withdraw such proposal if there is less than 100% participation and shall notify all parties of such decision within ten (10)

days, or within twenty-four (24) hours if a drilling rig is on location, following expiration of the applicable response period.

If 100% subscription to the proposed operation is obtained, the proposing party shall promptly notify the Consenting Parties

of their proportionate interests in the operation and the party serving as Operator shall commence such operation within the

period provided in Article VI.B.1., subject to the same extension right as provided therein.

(b) Relinquishment of Interest for Non-Participation. The entire cost and risk of conducting such operations shall be

borne by the Consenting Parties in the proportions they have elected to bear same under the terms of the preceding

paragraph.  Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and

encumbrances of every kind created by or arising from the operations of the Consenting Parties.  If such an operation results

in a dry hole, then subject to Articles VI.B.6. and VI.E.3., the Consenting Parties shall plug and abandon the well and restore

the surface location at their sole cost, risk and expense; provided, however, that those Non-Consenting Parties that

participated in the drilling, Deepening or Sidetracking of the well shall remain liable for, and shall pay, their proportionate

shares of the cost of plugging and abandoning the well and restoring the surface location insofar only as those costs were not

increased by the subsequent operations of the Consenting Parties.  If any well drilled, Reworked, Sidetracked, Deepened,

Recompleted or Plugged Back under the provisions of this Article results in a well capable of producing Oil and/or Gas in

paying quantities, the Consenting Parties shall Complete and equip the well to produce at their sole cost and risk, and the

well shall then be turned over to Operator (if the Operator did not conduct the operation) and shall be operated by it at the

expense and for the account of the Consenting Parties.  Upon commencement of operations for the drilling, Reworking,

Sidetracking, Recompleting, Deepening or Plugging Back of any such well by Consenting Parties in accordance with the

provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting Parties, and the

Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non-

Consenting Party's interest in the well and share of production therefrom or, in the case of a Reworking, Sidetracking,

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

Deepening, Recompleting or Plugging Back, or a Completion pursuant to Article VI.C.1.  Option No. 2, all of such Non-

Consenting Party's interest in the production obtained from the operation in which the Non-Consenting Party did not elect

to participate.  Such relinquishment shall be effective until the proceeds of the sale of such share, calculated at the well, or

market value thereof if such share is not sold (after deducting applicable ad valorem, production, severance, and excise taxes,

royalty, overriding royalty and other interests not excepted by Article III.C. payable out of or measured by the production

from such well accruing with respect to such interest until it reverts), shall equal the total of the following:

(i)      100          % of each such Non-Consenting Party's share of the cost of any newly acquired surface equipment

beyond the wellhead connections (including but not limited to stock tanks, separators, treaters, pumping equipment and

piping), plus 100% of each such Non-Consenting Party's share of the cost of operation of the well commencing with first

production and continuing until each such Non-Consenting Party's relinquished interest shall revert to it under other

provisions of this Article, it being agreed that each Non-Consenting Party's share of such costs and equipment will be that

interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning

of the operations; and

(ii) 200               % of (a) that portion of the costs and expenses of drilling, Reworking, Sidetracking, Deepening,

Plugging Back, testing, Completing, and Recompleting, after deducting any cash contributions received under Article VIII.C.,

and of (b) that portion of the cost of newly acquired equipment in the well (to and including the wellhead connections),

which would have been chargeable to such Non-Consenting Party if it had participated therein.

Notwithstanding anything to the contrary in this Article VI.B., if the well does not reach the deepest objective Zone

described in the notice proposing the well for reasons other than the encountering of granite or practically impenetrable

substance or other condition in the hole rendering further operations impracticable, Operator shall give notice thereof to each

Non-Consenting Party who submitted or voted for an alternative proposal under Article VI.B.6. to drill the well to a

shallower Zone than the deepest objective Zone proposed in the notice under which the well was drilled, and each such Non-

Consenting Party shall have the option to participate in the initial proposed Completion of the well by paying its share of the

cost of drilling the well to its actual depth, calculated in the manner provided in Article VI.B.4. (a).  If any such Non-

Consenting Party does not elect to participate in the first Completion proposed for such well, the relinquishment provisions

of this Article VI.B.2. (b) shall apply to such party's interest.

(c) Reworking, Recompleting or Plugging Back. An election not to participate in the drilling, Sidetracking or

Deepening of a well shall be deemed an election not to participate in any Reworking or Plugging Back operation proposed in

such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full

recovery by the Consenting Parties of the Non-Consenting Party's recoupment amount.  Similarly, an election not to

participate in the Completing or Recompleting of a well shall be deemed an election not to participate in any Reworking

operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at

any time prior to full recovery by the Consenting Parties of the Non-Consenting Party's recoupment amount.  Any such

Reworking, Recompleting or Plugging Back operation conducted during the recoupment period shall be deemed part of the

cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties __  300  ____% of

that portion of the costs of the Reworking, Recompleting or Plugging Back operation which would have been chargeable to

such Non-Consenting Party had it participated therein.  If such a Reworking, Recompleting or Plugging Back operation is

proposed during such recoupment period, the provisions of this Article VI.B. shall be applicable as between said Consenting

Parties in said well.

(d) Recoupment Matters. During the period of time Consenting Parties are entitled to receive Non-Consenting Party's

share of production, or the proceeds therefrom, Consenting Parties shall be responsible for the payment of all ad valorem,

production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to

Non-Consenting Party's share of production not excepted by Article III.C.

In the case of any Reworking, Sidetracking, Plugging Back, Recompleting or Deepening operation, the Consenting

Parties shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all

such equipment shall remain unchanged; and upon abandonment of a well after such Reworking, Sidetracking, Plugging Back,

Recompleting or Deepening, the Consenting Parties shall account for all such equipment to the owners thereof, with each

party receiving its proportionate part in kind or in value, less cost of salvage.

Within ninety (90) days after the completion of any operation under this Article, the party conducting the operations

for the Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to

the well, and an itemized statement of the cost of drilling, Sidetracking, Deepening, Plugging Back, testing, Completing,

Recompleting, and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement

quarter

of such costs of operation, may submit a detailed statement of monthly billings.  Each month / thereafter, during the time the

Consenting Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties

shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities incurred in the operation of

the well, together with a statement of the quantity of Oil and Gas produced from it and the amount of proceeds realized from

    quarter

the sale of the well's working interest production during the preceding month /.  In determining the quantity of Oil and Gas

produced during any month, Consenting Parties shall use industry accepted methods such as but not limited to metering or

periodic well tests.  Any amount realized from the sale or other disposition of equipment newly acquired in connection with

any such operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited

against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such

Non-Consenting Party shall revert to it as above provided; and if there is a credit balance, it shall be paid to such Non-

Consenting Party.

If and when the Consenting Parties recover from a Non-Consenting Party's relinquished interest the amounts provided

            1st day of the month

for above, the relinquished interests of such Non-Consenting Party shall automatically revert to it as of 7:00 a.m. on the day /

following the day on which such recoupment occurs, and, from and after such reversion, such Non-Consenting Party shall

own the same interest in such well, the material and equipment in or pertaining thereto, and the production therefrom as

such Non-Consenting Party would have been entitled to had it participated in the drilling, Sidetracking, Reworking,

Deepening, Recompleting or Plugging Back of said well.  Thereafter, such Non-Consenting Party shall be charged with and

shall pay its proportionate part of the further costs of the operation of said well in accordance with the terms of this

agreement and Exhibit "C" attached hereto.

3. Stand-By Costs: When a well which has been drilled or Deepened has reached its authorized depth and all tests have

been completed and the results thereof furnished to the parties, or when operations on the well have been otherwise

terminated pursuant to Article VI.F., stand-by costs incurred pending response to a party's notice proposing a Reworking,

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

Sidetracking, Deepening, Recompleting, Plugging Back or Completing operation in such a well (including the period required

under Article VI.B.6. to resolve competing proposals) shall be charged and borne as part of the drilling or Deepening

operation just completed.  Stand-by costs subsequent to all parties responding, or expiration of the response time permitted,

whichever first occurs, and prior to agreement as to the participating interests of all Consenting Parties pursuant to the terms

of the second grammatical paragraph of Article VI.B.2. (a), shall be charged to and borne as part of the proposed operation,

but if the proposal is subsequently withdrawn because of insufficient participation, such stand-by costs shall be allocated

between the Consenting Parties in the proportion each Consenting Party's interest as shown on Exhibit "A" bears to the total

interest as shown on Exhibit "A" of all Consenting Parties.

In the event that notice for a Sidetracking operation is given while the drilling rig to be utilized is on location, any party

may request and receive up to five (5) additional days after expiration of the forty-eight hour response period specified in

Article VI.B.1. within which to respond by paying for all stand-by costs and other costs incurred during such extended

response period; Operator may require such party to pay the estimated stand-by time in advance as a condition to extending

the response period.  If more than one party elects to take such additional time to respond to the notice, standby costs shall be

allocated between the parties taking additional time to respond on a day-to-day basis in the proportion each electing party's

interest as shown on Exhibit "A" bears to the total interest as shown on Exhibit "A" of all the electing parties.

4. Deepening: If less than all parties elect to participate in a drilling, Sidetracking, or Deepening operation proposed

pursuant to Article VI.B.1., the interest relinquished by the Non-Consenting Parties to the Consenting Parties under Article

VI.B.2. shall relate only and be limited to the lesser of (i) the total depth actually drilled or (ii) the objective depth or Zone

of which the parties were given notice under Article VI.B.1. ("Initial Objective").  Such well shall not be Deepened beyond the

Initial Objective without first complying with this Article to afford the Non-Consenting Parties the opportunity to participate

in the Deepening operation.

In the event any Consenting Party desires to drill or Deepen a Non-Consent Well to a depth below the Initial Objective,

such party shall give notice thereof, complying with the requirements of Article VI.B.1., to all parties (including Non-

Consenting Parties).  Thereupon, Articles VI.B.1. and 2. shall apply and all parties receiving such notice shall have the right to

participate or not participate in the Deepening of such well pursuant to said Articles VI.B.1. and 2.  If a Deepening operation

is approved pursuant to such provisions, and if any Non-Consenting Party elects to participate in the Deepening operation,

such Non-Consenting party shall pay or make reimbursement (as the case may be) of the following costs and expenses.

(a) If the proposal to Deepen is made prior to the Completion of such well as a well capable of producing in paying

quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) that share of costs

and expenses incurred in connection with the drilling of said well from the surface to the Initial Objective which Non-

Consenting Party would have paid had such Non-Consenting Party agreed to participate therein, plus the Non-Consenting

Party's share of the cost of Deepening and of participating in any further operations on the well in accordance with the other

provisions of this Agreement; provided, however, all costs for testing and Completion or attempted Completion of the well

incurred by Consenting Parties prior to the point of actual operations to Deepen beyond the Initial Objective shall be for the

sole account of Consenting Parties.

(b) If the proposal is made for a Non-Consent Well that has been previously Completed as a well capable of producing

in paying quantities, but is no longer capable of producing in paying quantities, such Non-Consenting Party shall pay (or

reimburse Consenting Parties for, as the case may be) its proportionate share of all costs of drilling, Completing, and

equipping said well from the surface to the Initial Objective, calculated in the manner provided in paragraph (a) above, less

those costs recouped by the Consenting Parties from the sale of production from the well.  The Non-Consenting Party shall

also pay its proportionate share of all costs of re-entering said well.  The Non-Consenting Parties' proportionate part (based

on the percentage of such well Non-Consenting Party would have owned had it previously participated in such Non-Consent

Well) of the costs of salvable materials and equipment remaining in the hole and salvable surface equipment used in

connection with such well shall be determined in accordance with Exhibit "C."  If the Consenting Parties have recouped the

cost of drilling, Completing, and equipping the well at the time such Deepening operation is conducted, then a Non-

Consenting Party may participate in the Deepening of the well with no payment for costs incurred prior to re-entering the

well for Deepening

The foregoing shall not imply a right of any Consenting Party to propose any Deepening for a Non-Consent Well prior

to the drilling of such well to its Initial Objective without the consent of the other Consenting Parties as provided in Article

VI.F.

5. Sidetracking: Any party having the right to participate in a proposed Sidetracking operation that does not own an

interest in the affected wellbore at the time of the notice shall, upon electing to participate, tender to the wellbore owners its

proportionate share (equal to its interest in the Sidetracking operation) of the value of that portion of the existing wellbore

to be utilized as follows:

(a) If the proposal is for Sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs

incurred in the initial drilling of the well down to the depth at which the Sidetracking operation is initiated.

(b) If the proposal is for Sidetracking a well which has previously produced, reimbursement shall be on the basis of

such party's proportionate share of drilling and equipping costs incurred in the initial drilling of the well down to the depth

at which the Sidetracking operation is conducted, calculated in the manner described in Article VI.B.4(b) above.  Such party's

proportionate share of the cost of the well's salvable materials and equipment down to the depth at which the Sidetracking

operation is initiated shall be determined in accordance with the provisions of Exhibit "C."

6. Order of Preference of Operations. Except as otherwise specifically provided in this agreement, if any party desires to

propose the conduct of an operation that conflicts with a proposal that has been made by a party under this Article VI, such

party shall have fifteen (15) days from delivery of the initial proposal, in the case of a proposal to drill a well or to perform

an operation on a well where no drilling rig is on location, or twenty-four (24) hours, exclusive of Saturday, Sunday and legal

holidays, from delivery of the initial proposal, if a drilling rig is on location for the well on which such operation is to be

conducted, to deliver to all parties entitled to participate in the proposed operation such party's alternative proposal, such

alternate proposal to contain the same information required to be included in the initial proposal.  Each party receiving such

proposals shall elect by delivery of notice to Operator within five (5) days after expiration of the proposal period, or within

twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) if a drilling rig is on location for the well that is the

subject of the proposals, to participate in one of the competing proposals.  Any party not electing within the time required

shall be deemed not to have voted.  The proposal receiving the vote of parties owning the largest aggregate percentage

interest of the parties voting shall have priority over all other competing proposals; in the case of a tie vote, the

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

initial proposal shall prevail. Operator shall deliver notice of such result to all parties entitled to participate in the operation

within five (5) days after expiration of the election period (or within twenty-four (24) hours, exclusive of Saturday, Sunday

and legal holidays, if a drilling rig is on location).  Each party shall then have two (2) days (or twenty-four (24) hours if a rig

is on location) from receipt of such notice to elect by delivery of notice to Operator to participate in such operation or to

relinquish interest in the affected well pursuant to the provisions of Article VI.B.2.; failure by a party to deliver notice within

such period shall be deemed an election not to participate in the prevailing proposal.

7. Conformity to Spacing Pattern. Notwithstanding the provisions of this Article VI.B.2., it is agreed that no wells shall be

proposed to be drilled to or Completed in or produced from a Zone from which a well located elsewhere on the Contract

or proposed

Area is producing, unless such well conforms to the then-existing well / spacing pattern for such Zone.

8. Paying Wells. No party shall conduct any Reworking, Deepening, Plugging Back, Completion, Recompletion, or

 Sidetracking operation under this agreement with respect to any well then capable of producing in paying quantities except

with the consent of all parties that have not relinquished interests in the well at the time of such operation.

C.  Completion of Wells; Reworking and Plugging Back:

1. Completion: Without the consent of all parties, no well shall be drilled, Deepened or Sidetracked, except any well

drilled, Deepened or Sidetracked pursuant to the provisions of Article VI.B.2. of this agreement.  Consent to the drilling,

Deepening or Sidetracking shall include:

o Option No. 1: All necessary expenditures for the drilling, Deepening or Sidetracking, testing, Completing and

equipping of the well, including necessary tankage and/or surface facilities.

þ Option No. 2: All necessary expenditures for the drilling, Deepening or Sidetracking and testing of the well. When

such well has reached its authorized depth, and all logs, cores and other tests have been completed, and the results

thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators having the right to

participate in a Completion attempt whether or not Operator recommends attempting to Complete the well,

together with Operator's AFE for Completion costs if not previously provided.  The parties receiving such notice

shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect by delivery of

notice to Operator to participate in a recommended Completion attempt or to make a Completion proposal with an

accompanying AFE.  Operator shall deliver any such Completion proposal, or any Completion proposal conflicting

with Operator's proposal, to the other parties entitled to participate in such Completion in accordance with the

procedures specified in Article VI.B.6.  Election to participate in a Completion attempt shall include consent to all

necessary expenditures for the Completing and equipping of such well, including necessary tankage and/or surface

facilities but excluding any stimulation operation not contained on the Completion AFE.  Failure of any party

receiving such notice to reply within the period above fixed shall constitute an election by that party not to

participate in the cost of the Completion attempt; provided, that Article VI.B.6. shall control in the case of

conflicting Completion proposals.  If one or more, but less than all of the parties, elect to attempt a Completion, the

provision of Article VI.B.2. hereof (the phrase "Reworking, Sidetracking, Deepening, Recompleting or Plugging

Back" as contained in Article VI.B.2. shall be deemed to include "Completing") shall apply to the operations

thereafter conducted by less than all parties; provided, however, that Article VI.B.2. shall apply separately to each

separate Completion or Recompletion attempt undertaken hereunder, and an election to become a Non-Consenting

Party as to one Completion or Recompletion attempt shall not prevent a party from becoming a Consenting Party

in subsequent Completion or Recompletion attempts regardless whether the Consenting Parties as to earlier

Completions or Recompletion have recouped their costs pursuant to Article VI.B.2.; provided further, that any

recoupment of costs by a Consenting Party shall be made solely from the production attributable to the Zone in

which the Completion attempt is made.  Election by a previous Non-Consenting party to participate in a subsequent

Completion or Recompletion attempt shall require such party to pay its proportionate share of the cost of salvable

materials and equipment installed in the well pursuant to the previous Completion or Recompletion attempt,

insofar and only insofar as such materials and equipment benefit the Zone in which such party participates in a

Completion attempt.

2. Rework, Recomplete or Plug Back: No well shall be Reworked, Recompleted or Plugged Back except a well Reworked,

Recompleted, or Plugged Back pursuant to the provisions of Article VI.B.2. of this agreement.  Consent to the Reworking,

Recompleting or Plugging Back of a well shall include all necessary expenditures in conducting such operations and

Completing and equipping of said well, including necessary tankage and/or surface facilities.

D.  Other Operations:

Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of

Fifty Thousand                                                                        Dollars ($                                50,000.00                          ) except in connection with the

drilling, Sidetracking, Reworking, Deepening, Completing, Recompleting or Plugging Back of a well that has been previously

authorized by or pursuant to this agreement; provided, however, that, in case of explosion, fire, flood or other sudden

emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion

are required to deal with the emergency to safeguard life and property but Operator, as promptly as possible, shall report the

emergency to the other parties.  If Operator prepares an AFE for its own use, Operator shall furnish any Non-Operator so

requesting an information copy thereof for any single project costing in excess of Fifty Thousand  Dollars

($     50,000.00).  Any party who has not relinquished its interest in a well shall have the right to propose that

Operator perform repair work or undertake the installation of artificial lift equipment or ancillary production facilities such as

salt water disposal wells or to conduct additional work with respect to a well drilled hereunder or other similar project (but

not including the installation of gathering lines or other transportation or marketing facilities, the installation of which shall

be governed by separate agreement between the parties) reasonably estimated to require an expenditure in excess of the

amount first set forth above in this Article VI.D. (except in connection with an operation required to be proposed under

Articles VI.B.1. or VI.C.1. Option No. 2, which shall be governed exclusively be those Articles).  Operator shall deliver such

proposal to all parties entitled to participate therein.  If within thirty (30) days thereof Operator secures the written consent

of any party or parties owning at least                                                                50           % of the interests of the parties entitled to participate in such operation,

each party having the right to participate in such project shall be bound by the terms of such proposal and shall be obligated

to pay its proportionate share of the costs of the proposed project as if it had consented to such project pursuant to the terms

of the proposal.

E.  Abandonment of Wells:

1.  Abandonment of Dry Holes: Except for any well drilled or Deepened pursuant to Article VI.B.2., any well which has

been drilled or Deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

plugged and abandoned without the consent of all parties.  Should Operator, after diligent effort, be unable to contact any

party, or should any party fail to reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after

delivery of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the

proposed abandonment.  All such wells shall be plugged and abandoned in accordance with applicable regulations and at the

operator

cost, risk and expense of the / parties who participated in the cost of drilling or Deepening such well.  Any party who objects to

plugging and abandoning such well by notice delivered to Operator within forty-eight (48) hours (exclusive of Saturday,

Sunday and legal holidays) after delivery of notice of the proposed plugging shall take over the well as of the end of such

forty-eight (48) hour notice period and conduct further operations in search of Oil and/or Gas subject to the provisions of

Article VI.B.; failure of such party to provide proof reasonably satisfactory to Operator of its financial capability to conduct

such operations or to take over the well within such period or thereafter to conduct operations on such well or plug and

abandon such well shall entitle Operator to retain or take possession of the well and plug and abandon the well.  The party

taking over the well shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against

liability for any further operations conducted on such well except for the costs of plugging and abandoning the well and

restoring the surface, for which the abandoning parties shall remain proportionately liable.

2. Abandonment of Wells That Have Produced: Except for any well in which a Non-Consent operation has been

conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has

been completed as a producer shall not be plugged and abandoned without the consent of all parties.  If all parties consent to

such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk

thirty (30)

and expense of all the parties hereto.  Failure of a party to reply within sixty (60) / days of delivery of notice of proposed

thirty (30)

abandonment shall be deemed an election to consent to the proposal.  If, within sixty (60) / days after delivery of notice of the

proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its

operation from the Zone then open to production shall be obligated to take over the well as of the expiration of the

applicable notice period and shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties

against liability for any further operations on the well conducted by such parties.  Failure of such party or parties to provide

proof reasonably satisfactory to Operator of their financial capability to conduct such operations or to take over the well

within the required period or thereafter to conduct operations on such well shall entitle operator to retain or take possession

of such well and plug and abandon the well.

Parties taking over a well as provided herein shall tender to each of the other parties its proportionate share of the value of

the well's salvable material and equipment, determined in accordance with the provisions of Exhibit "C," less the estimated cost

of salvaging and the estimated cost of plugging and abandoning and restoring the surface; provided, however, that in the event

the estimated plugging and abandoning and surface restoration costs and the estimated cost of salvaging are higher than the

value of the well's salvable material and equipment, each of the abandoning parties shall tender to the parties continuing

operations their proportionate shares of the estimated excess cost.  Each abandoning party shall assign to the non-abandoning

parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all

of its interest in the wellbore of the well and related equipment, together with its interest in the Leasehold insofar and only

insofar as such Leasehold covers the right to obtain production from that wellbore in the Zone then open to production.  If the

interest of the abandoning party is or includes and Oil and Gas Interest, such party shall execute and deliver to the non-

abandoning party or parties an oil and gas lease, limited to the wellbore and the Zone then open to production, for a term of

one (1) year and so long thereafter as Oil and/or Gas is produced from the Zone covered thereby, such lease to be on the form

attached as Exhibit "B."  The assignments or leases so limited shall encompass the Drilling Unit upon which the well is located.

The payments by, and the assignments or leases to, the assignees shall be in a ratio based upon the relationship of their

respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract

Area of all assignees.  There shall be no readjustment of interests in the remaining portions of the Contract Area.

Thereafter, abandoning parties shall have no further responsibility, liability, or interest in the operation of or production

from the well in the Zone then open other than the royalties retained in any lease made under the terms of this Article.  Upon

request, Operator shall continue to operate the assigned well for the account of the non-abandoning parties at the rates and

charges contemplated by this agreement, plus any additional cost and charges which may arise as the result of the separate

ownership of the assigned well.  Upon proposed abandonment of the producing Zone assigned or leased, the assignor or lessor

shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in

further operations therein subject to the provisions hereof.

3. Abandonment of Non-Consent Operations: The provisions of Article VI.E.1. or VI.E.2. above shall be applicable as

between Consenting Parties in the event of the proposed abandonment of any well excepted from said Articles; provided,

however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further

operations therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well

in accordance with the provisions of this Article VI.E.; and provided further, that Non-Consenting Parties who own an interest

in a portion of the well shall pay their proportionate shares of abandonment and surface restoration cost for such well as

provided in Article VI.B.2.(b).

F.  Termination of Operations:

Upon the commencement of an operation for the drilling, Reworking, Sidetracking, Plugging Back, Deepening, testing,

Completion or plugging of a well, including but not limited to the Initial Well, such operation shall not be terminated without

consent of parties bearing   51%___% of the costs of such operation; provided, however, that in the event granite or other

practically impenetrable substance or condition in the hole is encountered which renders further operations impractical,

Operator may discontinue operations and give notice of such condition in the manner provided in Article VI.B.1, and the

provisions of Article VI.B. or VI.E. shall thereafter apply to such operation, as appropriate.

G.  Taking Production in Kind:

þ     Option No. 1: Gas Balancing Agreement Attached

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from the

Contract Area, exclusive of production which may be used in development and producing operations and in preparing and

treating Oil and Gas for marketing purposes and production unavoidably lost.  Any extra expenditure incurred in the taking

in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party.  Any

party taking its share of production in kind shall be required to pay for only its proportionate share of such part of

Operator's surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in

**  only in so far as production from the Drilling Unit is attributable to that wellbore.

production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

directly from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate

share of the Oil produced from the Contract Area, Operator shall have the right, subject to the revocation at will by

the party owning it, but not the obligation, to purchase such Oil or sell it to others at any time and from time to

time, for the account of the non-taking party.  Any such purchase or sale by Operator may be terminated by

thirty (30)

Operator upon at least ten (10) / days written notice to the owner of said production and shall be subject always to

thirty (30)

the right of the owner of the production upon at least ten (10) / days written notice to Operator to exercise at any

time its right to take in kind, or separately dispose of, its share of all Oil not previously delivered to a purchaser.

Any purchase or sale by Operator of any other party's share of Oil shall be only for such reasonable periods of time

as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a

period in excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the circumstances but Operator

shall have no duty to share any existing market or to obtain a price equal to that received under any existing

market.  The sale or delivery by Operator of a non-taking party's share of Oil under the terms of any existing

contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said

contract.  No purchase shall be made by Operator without first giving the non-taking party at least ten (10) days

written notice of such intended purchase and the price to be paid or the pricing basis to be used.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following

month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements.

Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which

records shall be made available to Non-Operators upon reasonable request.

In the event one or more parties' separate disposition of its share of the Gas causes split-stream deliveries to separate

pipelines and/or deliveries which on a day-to-day basis for any reason are not exactly equal to a party's respective proportion-

ate share of total Gas sales to be allocated to it, the balancing or accounting between the parties shall be in accordance with

any Gas balancing agreement between the parties hereto, whether such an agreement is attached as Exhibit "E" or is a

separate agreement.  Operator shall give notice to all parties of the first sales of Gas from any well under this agreement.

o     Option No. 2: No Gas Balancing Agreement:

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from

the Contract Area, exclusive of production which may be used in development and producing operations and in

preparing and treating Oil and Gas for marketing purposes and production unavoidably lost.  Any extra expenditures

incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall

be borne by such party.  Any party taking its share of production in kind shall be required to pay for only its

proportionate share of such part of Operator's surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in

production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment

directly from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate

share of the Oil and/or Gas produced from the Contract Area, Operator shall have the right, subject to the

revocation at will by the party owning it, but not the obligation, to purchase such Oil and/or Gas or sell it to others

at any time and from time to time, for the account of the non-taking party.  Any such purchase or sale by Operator

may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall

be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator

to exercise its right to take in kind, or separately dispose of, its share of all Oil and/or Gas not previously delivered

to a purchaser; provided, however, that the effective date of any such revocation may be deferred at Operator's

election for a period not to exceed ninety (90) days if Operator has committed such production to a purchase

contract having a term extending beyond such ten (10) -day period.  Any purchase or sale by Operator of any other

party's share of Oil and/or Gas shall be only for such reasonable periods of time as are consistent with the

minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1)

year.

Any such sale by Operator shall be in a manner commercially reasonable under the circumstances, but Operator

shall have no duty to share any existing market or transportation arrangement or to obtain a price or transportation

fee equal to that received under any existing market or transportation arrangement.  The sale or delivery by

Operator of a non-taking party's share of production under the terms of any existing contract of Operator shall not

give the non-taking party any interest in or make the non-taking party a party to said contract.  No purchase of Oil

and Gas and no sale of Gas shall be made by Operator without first giving the non-taking party ten days written

notice of such intended purchase or sale and the price to be paid or the pricing basis to be used. Operator shall give

notice to all parties of the first sale of Gas from any well under this Agreement.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following

month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements.

Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which

records shall be made available to Non-Operators upon reasonable request.

ARTICLE VII.

EXPENDITURES AND LIABILITY OF PARTIES

A.  Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations,

and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area.  Accordingly, the

liens granted among the parties in Article VII.B. are given to secure only the debts of each severally, and no party shall have

any liability to third parties hereunder to satisfy the default of any other party in the payment of any expense or obligation

hereunder.  It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other

partnership, joint venture, agency relationship or association, or to render the parties liable as partners, co-venturers, or

principals.  In their relations with each other under this agreement, the parties shall not be considered fiduciaries or to have

established a confidential relationship but rather shall be free to act on an arm's-length basis in accordance with their own

respective self-interest, subject, however, to the obligation of the parties to act in good faith in their dealings with each other

with respect to activities hereunder.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

B.  Liens and Security Interests:

Each party grants to the other parties hereto a lien upon any interest it now owns or hereafter acquires in Oil and Gas

Leases and Oil and Gas Interests in the Contract Area, and a security interest and/or purchase money security interest in any

interest it now owns or hereafter acquires in the personal property and fixtures on or used or obtained for use in connection

therewith, to secure performance of all of its obligations under this agreement including but not limited to payment of expense,

interest and fees, the proper disbursement of all monies paid hereunder, the assignment or relinquishment of interest in Oil

and Gas Leases as required hereunder, and the proper performance of operations hereunder.  Such lien and security interest

granted by each party hereto shall include such party's leasehold interests, working interests, operating rights, and royalty and

overriding royalty interests in the Contract Area now owned or hereafter acquired and in lands pooled or unitized therewith or

otherwise becoming subject to this agreement, the Oil and Gas when extracted therefrom and equipment situated thereon or

used or obtained for use in connection therewith (including, without limitation, all wells, tools, and tubular goods), and accounts

(including, without limitation, accounts arising from gas imbalances or from the sale of Oil and/or Gas at the wellhead),

contract rights, inventory and general intangibles relating thereto or arising therefrom, and all proceeds and products of the

foregoing.

To perfect the lien and security agreement provided herein, each party hereto shall execute and acknowledge the recording

supplement and/or any financing statement prepared and submitted by any party hereto in conjunction herewith or at any time

a memorandum of

following execution hereof, and Operator is authorized to file / this agreement or the recording supplement executed herewith as

a lien or mortgage in the applicable real estate records and as a financing statement with the proper officer under the Uniform

Commercial Code in the state in which the Contract Area is situated and such other states as Operator shall deem appropriate

a memorandum of

to perfect the security interest granted hereunder.  Any party may file / this agreement, the recording supplement executed

herewith, or such other documents as it deems necessary as a lien or mortgage in the applicable real estate records and/or a

financing statement with the proper officer under the Uniform Commercial Code.

Each party represents and warrants to the other parties hereto that the lien and security interest granted by such party to

the other parties shall be a first and prior lien, and each party hereby agrees to maintain the priority of said lien and security

interest against all persons acquiring an interest in Oil and Gas Leases and Interests covered by this agreement by, through or

under such party.  All parties acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by this agreement,

whether by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed to have taken subject

to the lien and security interest granted by this Article VII.B. as to all obligations attributable to such interest hereunder

whether or not such obligations arise before or after such interest is acquired.

To the extent that parties have a security interest under the Uniform Commercial Code of the state in which the

Contract Area is situated, they shall be entitled to exercise the rights and remedies of a secured party under the Code.

The bringing of a suit and the obtaining of judgment by a party for the secured indebtedness shall not be deemed an

election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof.  In

addition, upon default by any party in the payment of its share of expenses, interests or fees, or upon the improper use

of funds by the Operator, the other parties shall have the right, without prejudice to other rights or remedies, to collect

from the purchaser the proceeds from the sale of such defaulting party's share of Oil and Gas until the amount owed by

such party, plus interest as provided in "Exhibit C," has been received, and shall have the right to offset the amount

owed against the proceeds from the sale of such defaulting party's share of Oil and Gas.  All purchasers of production

may rely on a notification of default from the non-defaulting party or parties stating the amount due as a result of the

default, and all parties waive any recourse available against purchasers for releasing production proceeds as provided in

this paragraph.

If any party fails to pay its share of cost within one hundred twenty (120) days after rendition of a statement therefor by

Operator, the non-defaulting parties, including Operator, shall upon request by Operator, pay the unpaid amount in the

proportion that the interest of each such party bears to the interest of all such parties.  The amount paid by each party so

paying its share of the unpaid amount shall be secured by the liens and security rights described in Article VII.B., and each

paying party may independently pursue any remedy available hereunder or otherwise.

If any party does not perform all of its obligations hereunder, and the failure to perform subjects such party to foreclosure

or execution proceedings pursuant to the provisions of this agreement, to the extent allowed by governing law, the defaulting

party waives any available right of redemption from and after the date of judgment, any required valuation or appraisement

of the mortgaged or secured property prior to sale, any available right to stay execution or to require a marshaling of assets

and any required bond in the event a receiver is appointed.  In addition, to the extent permitted by applicable law, each party

hereby grants to the other parties a power of sale as to any property that is subject to the lien and security rights granted

hereunder, such power to be exercised in the manner provided by applicable law or otherwise in a commercially reasonable

manner and upon reasonable notice.

Each party agrees that the other parties shall be entitled to utilize the provisions of Oil and Gas lien law or other lien

law of any state in which the Contract Area is situated to enforce the obligations of each party hereunder.  Without limiting

the generality of the foregoing, to the extent permitted by applicable law, Non-Operators agree that Operator may invoke or

utilize the mechanics' or materialmen's lien law of the state in which the Contract Area is situated in order to secure the

payment to Operator of any sum due hereunder for services performed or materials supplied by Operator.

C.  Advances:

Operator, at its election, shall have the right from time to time to demand and receive from one or more of the other

parties payment in advance of their respective shares of the estimated amount of the expense to be incurred in operations

hereunder during the next succeeding month, which right may be exercised only by submission to each such party of an

itemized statement of such estimated expense, together with an invoice for its share thereof.  Each such statement and invoice

for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month.

Each party shall pay to Operator its proportionate share of such estimate within fifteen (15) days after such estimate and

invoice is received.  If any party fails to pay its share of said estimate within said time, the amount due shall bear interest as

provided in Exhibit "C" until paid.  Proper adjustment shall be made monthly between advances and actual expense to the end

that each party shall bear and pay its proportionate share of actual expenses incurred, and no more.

D.  Defaults and Remedies:

If any party fails to discharge any financial obligation under this agreement, including without limitation the failure to

make any advance under the preceding Article VII.C. or any other provision of this agreement, within the period required for

such payment hereunder, then in addition to the remedies provided in Article VII.B. or elsewhere in this agreement, the

remedies specified below shall be applicable.  For purposes of this Article VII.D., all notices and elections shall be delivered

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

only by Operator, except that Operator shall deliver any such notice and election requested by a non-defaulting Non-Operator,

and when Operator is the party in default, the applicable notices and elections can be delivered by any Non-Operator.

Election of any one or more of the following remedies shall not preclude the subsequent use of any other remedy specified

below or otherwise available to a non-defaulting party.

1. Suspension of Rights: Any party may deliver to the party in default a Notice of Default, which shall specify the default,

specify the action to be taken to cure the default, and specify that failure to take such action will result in the exercise of one

or more of the remedies provided in this Article.  If the default is not cured within thirty (30) days of the delivery of such

Notice of Default, all of the rights of the defaulting party granted by this agreement may upon notice be suspended until the

default is cured, without prejudice to the right of the non-defaulting party or parties to continue to enforce the obligations of

the defaulting party previously accrued or thereafter accruing under this agreement.  If Operator is the party in default, the

Non-Operators shall have in addition the right, by vote of Non-Operators owning a majority in interest in the Contract Area

after excluding the voting interest of Operator, to appoint a new Operator effective immediately.  The rights of a defaulting

party that may be suspended hereunder at the election of the non-defaulting parties shall include, without limitation, the right

to receive information as to any operation conducted hereunder during the period of such default, the right to elect to

participate in an operation proposed under Article VI.B. of this agreement, the right to participate in an operation being

conducted under this agreement even if the party has previously elected to participate in such operation, and the right to

receive proceeds of production from any well subject to this agreement.

2. Suit for Damages: Non-defaulting parties or Operator for the benefit of non-defaulting parties may sue (at joint

account expense) to collect the amounts in default, plus interest accruing on the amounts recovered from the date of default

until the date of collection at the rate specified in Exhibit "C" attached hereto.  Nothing herein shall prevent any party from

suing any defaulting party to collect consequential damages accruing to such party as a result of the default.

3. Deemed Non-Consent: The non-defaulting party may deliver a written Notice of Non-Consent Election to the

defaulting party at any time after the expiration of the thirty-day cure period following delivery of the Notice of Default, in

which event if the billing is for the drilling a new well or the Plugging Back, Sidetracking, Reworking or Deepening of a

well which is to be or has been plugged as a dry hole, or for the Completion or Recompletion of any well, the defaulting

party will be conclusively deemed to have elected not to participate in the operation and to be a Non-Consenting Party with

respect thereto under Article VI.B. or VI.C., as the case may be, to the extent of the costs unpaid by such party,

notwithstanding any election to participate theretofore made.  If election is made to proceed under this provision, then the

non-defaulting parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2.

Until the delivery of such Notice of Non-Consent Election to the defaulting party, such party shall have the right to cure

its default by paying its unpaid share of costs plus interest at the rate set forth in Exhibit "C," provided, however, such

payment shall not prejudice the rights of the non-defaulting parties to pursue remedies for damages incurred by the non-

defaulting parties as a result of the default.  Any interest relinquished pursuant to this Article VII.D.3. shall be offered to the

non-defaulting parties in proportion to their interests, and the non-defaulting parties electing to participate in the ownership

of such interest shall be required to contribute their shares of the defaulted amount upon their election to participate therein.

4. Advance Payment: If a default is not cured within thirty (30) days of the delivery of a Notice of Default, Operator, or

Non-Operators if Operator is the defaulting party, may thereafter require advance payment from the defaulting

party of such defaulting party's anticipated share of any item of expense for which Operator, or Non-Operators, as the case may

be, would be entitled to reimbursement under any provision of this agreement, whether or not such expense was the subject of

the previous default.  Such right includes, but is not limited to, the right to require advance payment for the estimated costs of

drilling a well or Completion of a well as to which an election to participate in drilling or Completion has been made.  If the

defaulting party fails to pay the required advance payment, the non-defaulting parties may pursue any of the remedies provided

in the Article VII.D. or any other default remedy provided elsewhere in this agreement.  Any excess of funds advanced remaining

when the operation is completed and all costs have been paid shall be promptly returned to the advancing party.

5. Costs and Attorneys' Fees: In the event any party is required to bring legal proceedings to enforce any financial

obligation of a party hereunder, the prevailing party in such action shall be entitled to recover all court costs, costs of

collection, and a reasonable attorney's fee, which the lien provided for herein shall also secure.

E.  Rentals, Shut-in Well Payments and Minimum Royalties:

Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid

by the party or parties who subjected such lease to this agreement at its or their expense.  In the event two or more parties

own and have contributed interests in the same lease to this agreement, such parties may designate one of such parties to

make said payments for and on behalf of all such parties.  Any party may request, and shall be entitled to receive, proper

evidence of all such payments.  In the event of failure to make proper payment of any rental, shut-in well payment or

minimum royalty through mistake or oversight where such payment is required to continue the lease in force, any loss which

results from such non-payment shall be borne in accordance with the provisions of Article IV.B.2.

Operator shall notify Non-Operators of the anticipated completion of a shut-in well, or the shutting in or return to

production of a producing well, at least five (5) days (excluding Saturday, Sunday, and legal holidays) prior to taking such

action, or at the earliest opportunity permitted by circumstances, but assumes no liability for failure to do so.  In the event of

failure by Operator to so notify Non-Operators, the loss of any lease contributed hereto by Non-Operators for failure to make

timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article

IV.B.3.

F.  Taxes:

Beginning with the first calendar year after the effective date hereof, Operator shall render for ad valorem taxation all

property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed

thereon before they become delinquent.  Prior to the rendition date, each Non-Operator shall furnish Operator information as

to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on Leases and Oil and

Gas Interests contributed by such Non-Operator.  If the assessed valuation of any Lease is reduced by reason of its being

subject to outstanding excess royalties, overriding royalties or production payments, the reduction in ad valorem taxes

resulting therefrom shall inure to the benefit of the owner or owners of such Lease, and Operator shall adjust the charge to

such owner or owners so as to reflect the benefit of such reduction.  If the ad valorem taxes are based in whole or in part

upon separate valuations of each party's working interest, then notwithstanding anything to the contrary herein, charges to

the joint account shall be made and paid by the parties hereto in accordance with the tax value generated by each party's

working interest.  Operator shall bill the other parties for their proportionate shares of all tax payments in the manner

provided in Exhibit "C."

-  -

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

If Operator considers any tax assessment improper, Operator may, at its discretion, protest within the time and manner

prescribed by law, and prosecute the protest to a final determination, unless all parties agree to abandon the protest prior to final

determination.  During the pendency of administrative or judicial proceedings, Operator may elect to pay, under protest, all such taxes

and any interest and penalty.  When any such protested assessment shall have been finally determined, Operator shall pay the tax for

the joint account, together with any interest and penalty accrued, and the total cost shall then be assessed against the parties, and be

paid by them, as provided in Exhibit "C."

Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect

to the production or handling of such party's share of Oil and Gas produced under the terms of this agreement.

ARTICLE VIII.

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A.  Surrender of Leases:

The Leases covered by this agreement, insofar as they embrace acreage in the Contract Area, shall not be surrendered in whole

or in part unless all parties consent thereto.

However, should any party desire to surrender its interest in any Lease or in any portion thereof, such party shall give written

notice of the proposed surrender to all parties, and the parties to whom such notice is delivered shall have thirty (30) days after

delivery of the notice within which to notify the party proposing the surrender whether they elect to consent thereto.  Failure of a

party to whom such notice is delivered to reply within said 30-day period shall constitute a consent to the surrender of the Leases

described in the notice.  If all parties do not agree or consent thereto, the party desiring to surrender shall assign, without express or

implied warranty of title, all of its interest in such Lease, or portion thereof, and any well, material and equipment which may be

located thereon and any rights in production thereafter secured, to the parties not consenting to such surrender.  If the interest of the

assigning party is or includes an Oil and Gas Interest, the assigning party shall execute and deliver to the party or parties not

consenting to such surrender an oil and gas lease covering such Oil and Gas Interest for a term of one (1) year and so long

thereafter as Oil and/or Gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit "B."

Upon such assignment or lease, the assigning party shall be relieved from all obligations thereafter accruing, but not theretofore

accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party

shall have no further interest in the assigned or leased premises and its equipment and production other than the royalties retained

in any lease made under the terms of this Article.  The party assignee or lessee shall pay to the party assignor or lessor the

reasonable salvage value of the latter's interest in any well's salvable materials and equipment attributable to the assigned or leased

acreage.  The value of all salvable materials and equipment shall be determined in accordance with the provisions of Exhibit "C," less

the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface.  If such value is less

than such costs, then the party assignor or lessor shall pay to the party assignee or lessee the amount of such deficit.  If the

assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the

interest of each bears to the total interest of all such parties.  If the interest of the parties to whom the assignment is to be made

varies according to depth, then the interest assigned shall similarly reflect such variances.

Any assignment, lease or surrender made under this provision shall not reduce or change the assignor's, lessor's or surrendering

party's interest as it was immediately before the assignment, lease or surrender in the balance of the Contract Area; and the acreage

assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this

agreement but shall be deemed subject to an Operating Agreement in the form of this agreement.

B. Renewal or Extension of Leases:

If any party secures a renewal or replacement of an Oil and Gas Lease or Interest subject to this agreement, then all other parties

shall be notified promptly upon such acquisition or, in the case of a replacement Lease taken before expiration of an existing Lease,

promptly upon expiration of the existing Lease.  The parties notified shall have the right for a period of thirty (30) days following

delivery of such notice in which to elect to participate in the ownership of the renewal or replacement Lease, insofar as such Lease

affects lands within the Contract Area, by paying to the party who acquired it their proportionate shares of the acquisition cost

allocated to that part of such Lease within the Contract Area, which shall be in proportion to the interest held at that time by the

parties in the Contract Area.  Each party who participates in the purchase of a renewal or replacement Lease shall be given an

assignment of its proportionate interest therein by the acquiring party.

If some, but less than all, of the parties elect to participate in the purchase of a renewal or replacement Lease, it shall be owned

by the parties who elect to participate therein, in a ratio based upon the relationship of their respective percentage of participation in

the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the

purchase of such renewal or replacement Lease.  The acquisition of a renewal or replacement Lease by any or all of the parties hereto

shall not cause a readjustment of the interests of the parties stated in Exhibit "A," but any renewal or replacement Lease in which

less than all parties elect to participate shall not be subject to this agreement but shall be deemed subject to a separate Operating

Agreement in the form of this agreement.

If the interests of the parties in the Contract Area vary according to depth, then their right to participate proportionately in

renewal or replacement Leases and their right to receive an assignment of interest shall also reflect such depth variances.

The provisions of this Article shall apply to renewal or replacement Leases whether they are for the entire interest covered by

        or lease nominated for sale that is

the expiring Lease or cover only a portion of its area or an interest therein.  Any renewal or replacement Lease / taken before the

expiration of its predecessor Lease, or taken or contracted for or becoming effective within six (6) months after the expiration of the

existing Lease, shall be subject to this provision so long as this agreement is in effect at the time of such acquisition or at the time

the renewal or replacement Lease becomes effective; but any Lease taken or contracted for more than six (6) months after the

expiration of an existing Lease shall not be deemed a renewal or replacement Lease and shall not be subject to the provisions of this

agreement.

The provisions in this Article shall also be applicable to extensions of Oil and Gas Leases.

C.  Acreage or Cash Contributions:

While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a well or any other

operation on the Contract Area, such contribution shall be paid to the party who conducted the drilling or other operation and shall

be applied by it against the cost of such drilling or other operation.  If the contribution be in the form of acreage, the party to whom

the contribution is made shall promptly tender an assignment of the acreage, without warranty of title, to the Drilling Parties in the

proportions said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to  the

extent possible, be governed by provisions identical to this agreement.  Each party shall promptly notify all other parties of any

acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area.  The above

provisions shall also be applicable to optional rights to earn acreage outside the Contract Area which are in support of well drilled

inside Contract Area.

-  -

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

If any party contracts for any consideration relating to disposition of such party's share of substances produced hereunder,

such consideration shall not be deemed a contribution as contemplated in this Article VIII.C.

D.  Assignment; Maintenance of Uniform Interest:

For the purpose of maintaining uniformity of ownership in the Contract Area in the Oil and Gas Leases, Oil and Gas

Interests, wells, equipment and production covered by this agreement no party shall sell, encumber, transfer or make other

disposition of its interest in the Oil and Gas Leases and Oil and Gas Interests embraced within the Contract Area or in wells,

equipment and production unless such disposition covers either:

1.      the entire interest of the party in all Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production; or

2.      an equal undivided percent of the party's present interest in all Oil and Gas Leases, Oil and Gas Interests, wells,

equipment and production in the Contract Area.

Every sale, encumbrance, transfer or other disposition made by any party shall be made expressly subject to this agreement

and shall be made without prejudice to the right of the other parties, and any transferee of an ownership interest in any Oil and

Gas Lease or Interest shall be deemed a party to this agreement as to the interest conveyed from and after the effective date of

the transfer of ownership; provided, however, that the other parties shall not be required to recognize any such sale,

encumbrance, transfer or other disposition for any purpose hereunder until thirty (30) days after they have received a copy of the

instrument of transfer or other satisfactory evidence thereof in writing from the transferor or transferee.  No assignment or other

disposition of interest by a party shall relieve such party of obligations previously incurred by such party hereunder with respect

to the interest transferred, including without limitation the obligation of a party to pay all costs attributable to an operation

conducted hereunder in which such party has agreed to participate prior to making such assignment, and the lien and security

interest granted by Article VII.B. shall continue to burden the interest transferred to secure payment of any such obligations.

two

If, at any time the interest of any party is divided among and owned by four / or more co-owners, Operator, at its discretion,

may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures,

receive billings for and approve and pay such party's share of the joint expenses, and to deal generally with, and with power to

bind, the co-owners of such party's interest within the scope of the operations embraced in this agreement; however, all such co-

owners shall have the right to enter into and execute all contracts or agreements for the disposition of their respective shares of

the Oil and Gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale

proceeds thereof.

E. Waiver of Rights to Partition:

If permitted by the laws of the state or states in which the property covered hereby is located, each party hereto owning an

undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its

undivided interest therein.

F.  Preferential Right to Purchase:

o     (Optional; Check if applicable.)

Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract

Area, it shall promptly give written notice to the other parties, with full information concerning its proposed disposition, which

shall include the name and address of the prospective transferee (who must be ready, willing and able to purchase), the purchase

price, a legal description sufficient to identify the property, and all other terms of the offer.  The other parties shall then have an

optional prior right, for a period of ten (10) days after the notice is delivered, to purchase for the stated consideration on the

same terms and conditions the interest which the other party proposes to sell; and, if this optional right is exercised, the

purchasing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all

purchasing parties.  However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage

its interests, or to transfer title to its interests to its mortgagee in lieu of or pursuant to foreclosure of a mortgage of its interests,

or to dispose of its interests by merger, reorganization, consolidation, or by sale of all or substantially all of its Oil and Gas assets

to any party, or by transfer of its interests to a subsidiary or parent company or to a subsidiary of a parent company, or to any

company in which such party owns a majority of the stock.

ARTICLE IX.

INTERNAL REVENUE CODE ELECTION  (SEE ARTICLE XVI)

If, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, and if the

parties have not otherwise agreed to form a tax partnership pursuant to Exhibit "G" or other agreement between them, each

party thereby affected elects to be excluded from the application of all of the provisions of Subchapter "K," Chapter 1, Subtitle

"A," of the Internal Revenue Code of 1986, as amended ("Code"), as permitted and authorized by Section 761 of the Code and

the regulations promulgated thereunder.  Operator is authorized and directed to execute on behalf of each party hereby affected

such evidence of this election as may be required by the Secretary of the Treasury of the United States or the Federal Internal

Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by

Treasury Regulation §1.761.  Should there be any requirement that each party hereby affected give further evidence of this

election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal

Revenue Service or as may be necessary to evidence this election.  No such party shall give any notices or take any other action

inconsistent with the election made hereby.  If any present or future income tax laws of the state or states in which the Contract

Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter "K," Chapter

1, Subtitle "A," of the Code, under which an election similar to that provided by Section 761 of the Code is permitted, each party

hereby affected shall make such election as may be permitted or required by such laws.  In making the foregoing election, each

such party states that the income derived by such party from operations hereunder can be adequately determined without the

computation of partnership taxable income.

ARTICLE X.

CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure

does not exceed                                                               Fifty Thousand                                                                        Dollars ($50,000.00 ) and if the payment is in complete settlement

of such claim or suit.  If the amount required for settlement exceeds the above amount, the parties hereto shall assume and take over

the further handling of the claim or suit, unless such authority is delegated to Operator.  All costs and expenses of handling settling,

or otherwise discharging such claim or suit shall be a the joint expense of the parties participating in the operation from which the

claim or suit arises.  If a claim is made against any party or if any party is sued on account of any matter arising from operations

hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall

immediately notify all other parties, and the claim or suit shall be treated as any other claim or suit involving operations hereunder.

-  -

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

ARTICLE XI.

FORCE MAJEURE

If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other

than the obligation to indemnify or make money payments or furnish security, that party shall give to all other parties

prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the

party giving the notice, so far as they are affected by the force majeure, shall be suspended during, but no longer than, the

continuance of the force majeure.  The term "force majeure," as here employed, shall mean an act of God, strike, lockout, or

other industrial disturbance, act of the public enemy, war, blockade, public riot, lightening, fire, storm, flood or other act of

nature, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other

cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party

claiming suspension.

The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable. The

requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes,

lockouts, or other labor difficulty by the party involved, contrary to its wishes; how all such difficulties shall be handled shall

be entirely within the discretion of the party concerned.

ARTICLE XII.

NOTICES

All notices authorized or required between the parties by any of the provisions of this agreement, unless otherwise

specifically provided, shall be in writing and delivered in person or by United States mail, courier service, telegram, telex,

telecopier or any other form of facsimile, postage or charges prepaid, and addressed to such parties at the addresses listed on

Exhibit "A."  All telephone or oral notices permitted by this agreement shall be confirmed immediately thereafter by written

notice.  The originating notice given under any provision hereof shall be deemed delivered only when received by the party to

whom such notice is directed, and the time for such party to deliver any notice in response thereto shall run from the date

the originating notice is received.  "Receipt" for purposes of this agreement with respect to written notice delivered hereunder

shall be actual delivery of the notice to the address of the party to be notified specified in accordance with this agreement, or

to the telecopy, facsimile or telex machine of such party.  The second or any responsive notice shall be deemed delivered when

deposited in the United States mail or at the office of the courier or telegraph service, or upon transmittal by telex, telecopy

or facsimile, or when personally delivered to the party to be notified, provided, that when response is required within 24 or

48 hours, such response shall be given orally or by telephone, telex, telecopy or other facsimile within such period. Each party

shall have the right to change its address at any time, and from time to time, by giving written notice thereof to all other

parties.  If a party is not available to receive notice orally or by telephone when a party attempts to deliver a notice required

to be delivered within 24 or 48 hours, the notice may be delivered in writing by any other method specified herein and shall

be deemed delivered in the same manner provided above for any responsive notice.

ARTICLE XIII.

TERM OF AGREEMENT

This agreement shall remain in full force and effect as to the Oil and Gas Leases and/or Oil and Gas Interests subject

hereto for the period of time selected below; provided, however, no party hereto shall ever be construed as having any right, title

or interest in or to any Lease or Oil and Gas Interest contributed by any other party beyond the term of this agreement.

þ     Option No. 1: So long as any of the Oil and Gas Leases subject to this agreement remain or are continued in

force as to any part of the Contract Area, whether by production, extension, renewal or otherwise.

o     Option No. 2: In the event the well described in Article VI.A., or any subsequent well drilled under any provision

of this agreement, results in the Completion of a well as a well capable of production of Oil and/or Gas in paying

quantities, this agreement shall continue in force so long as any such well is capable of production, and for an

additional period of days thereafter; provided, however, if, prior to the expiration of such

additional period, one or more of the parties hereto are engaged in drilling, Reworking, Deepening, Sidetracking,

Plugging Back, testing or attempting to Complete or Re-complete a well or wells hereunder, this agreement shall

continue in force until such operations have been completed and if production results therefrom, this agreement

shall continue in force as provided herein.  In the event the well described in Article VI.A., or any subsequent well

drilled hereunder, results in a dry hole, and no other well is capable of producing Oil and/or Gas from the

Contract Area, this agreement shall terminate unless drilling, Deepening, Sidetracking, Completing, Re-

completing, Plugging Back or Reworking operations are commenced within days from the

date of abandonment of said well.  "Abandonment" for such purposes shall mean either (i) a decision by all parties

not to conduct any further operations on the well or (ii) the elapse of 180 days from the conduct of any

operations on the well, whichever first occurs.

The termination of this agreement shall not relieve any party hereto from any expense, liability or other obligation or any

remedy therefor which has accrued or attached prior to the date of such termination.

Upon termination of this agreement and the satisfaction of all obligations hereunder, in the event a memorandum of this

Operating Agreement has been filed of record, Operator is authorized to file of record in all necessary recording offices a

notice of termination, and each party hereto agrees to execute such a notice of termination as to Operator's interest, upon

request of Operator, if Operator has satisfied all its financial obligations.

ARTICLE XIV.

COMPLIANCE WITH LAWS AND REGULATIONS

A.  Laws, Regulations and Orders:

This agreement shall be subject to the applicable laws of the state in which the Contract Area is located, to the valid rules,

regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state,

and local laws, ordinances, rules, regulations and orders.

B.  Governing Law:

This agreement and all matters pertaining hereto, including but not limited to matters of performance, non-

performance, breach, remedies, procedures, rights, duties, and interpretation or construction, shall be governed and

determined by the law of the state in which the Contract Area is located.  If the Contract Area is in two or more states,

the law of the state of                                                       shall govern.

C.  Regulatory Agencies:

Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any

rights, privileges, or obligations which Non-Operators may have under federal or state laws or under rules, regulations or

-  -

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

orders promulgated under such laws in reference to oil, gas and mineral operations, including the location, operation, or

production of wells, on tracts offsetting or adjacent to the Contract Area.

With respect to the operations hereunder, Non-Operators agree to release Operator from any and all losses, damages,

injuries, claims and causes of action arising out of, incident to or resulting directly or indirectly from Operator's interpretation

or application of rules, rulings, regulations or orders of the Department of Energy or Federal Energy Regulatory Commission

or predecessor or successor agencies to the extent such interpretation or application was made in good faith and does not

constitute gross negligence.  Each Non-Operator further agrees to reimburse Operator for such Non-Operator's share of

production or any refund, fine, levy or other governmental sanction that Operator may be required to pay as a result of such

an incorrect interpretation or application, together with interest and penalties thereon owing by Operator as a result of such

incorrect interpretation or application.

ARTICLE XV.

MISCELLANEOUS

A.  Execution:

This agreement shall be binding upon each Non-Operator when this agreement or a counterpart thereof has been

executed by such Non-Operator and Operator notwithstanding that this agreement is not then or thereafter executed by all of

the parties to which it is tendered or which are listed on Exhibit "A" as owning an interest in the Contract Area or which

own, in fact, an interest in the Contract Area.  Operator may, however, by written notice to all Non-Operators who have

become bound by this agreement as aforesaid, given at any time prior to the actual spud date of the Initial Well but in no

event later than five days prior to the date specified in Article VI.A. for commencement of the Initial Well, terminate this

agreement if Operator in its sole discretion determines that there is insufficient participation to justify commencement of

drilling operations.  In the event of such a termination by Operator, all further obligations of the parties hereunder shall cease

as of such termination.  In the event any Non-Operator has advanced or prepaid any share of drilling or other costs

hereunder, all sums so advanced shall be returned to such Non-Operator without interest.   In the event Operator proceeds

with drilling operations for the Initial Well without the execution hereof by all persons listed on Exhibit "A" as having a

current working interest in such well, Operator shall indemnify Non-Operators with respect to all costs incurred for the

Initial Well which would have been charged to such person under this agreement if such person had executed the same and

Operator shall receive all revenues which would have been received by such person under this agreement if such person had

executed the same.

B. Successors and Assigns:

This agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective heirs,

devisees, legal representatives, successors and assigns, and the terms hereof shall be deemed to run with the Leases or

Interests included within the Contract Area.

C. Counterparts:

This instrument may be executed in any number of counterparts, each of which shall be considered an original for all

purposes.

D.  Severability:

For the purposes of assuming or rejecting this agreement as an executory contract pursuant to federal bankruptcy laws,

this agreement shall not be severable, but rather must be assumed or rejected in its entirety, and the failure of any party to

this agreement to comply with all of its financial obligations provided herein shall be a material default.

ARTICLE XVI.

OTHER PROVISIONS

See attached Article XVI.

-  -

A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

IN WITNESS WHEREOF, this agreement shall be effective as of the 1st day of May, 2011

.

 , who has prepared and circulated this form for execution, represents and warrants

that the form was printed from and, with the exception(s) listed below, is identical to the AAPL Form 610-1989 Model Form

Operating Agreement, as published in computerized form by Forms On-A-Disk, Inc. No changes, alterations, or

modifications, other than those made by strikethrough and/or insertion and that are clearly recognizable as changes in

Articles , have been made to the form.

ATTEST OR WITNESS:                                                                        OPERATOR

Encana Oil & Gas (USA) Inc.

          By /s/                                                 

John Schopp

Type or print name

Title   Vice President, North Rockies                                                           

Date   March 11, 2011                                                           

Tax ID or S.S. No.                                                              

NON-OPERATORS

Northwest Natural Gas Company

          By /s/                                                 

Gregg Kantor

Type or print name

Title  CEO                                              

Date February 24, 2011                                                            

Tax ID or S.S. No.                                                              

          By

Type or print name

Title                                                              

Date                                                              

Tax ID or S.S. No.                                                              

          By

Type or print name

Title                                                              

Date                                                              

Tax ID or S.S. No.                                                              

-  -

ACKNOWLEDGMENTS

Note: The following forms of acknowledgment are the short forms approved by the Uniform Law on Notarial Acts.

The validity and effect of these forms in any state will depend upon the statutes of that state.

Individual acknowledgment:

State of                               )

) ss.

County of                              )

This instrument was acknowledged before me on

 by

(Seal, if any)                                                                      

Title (and Rank)

My commission expires:

Acknowledgment in representative capacity:

State of                               )

) ss.

County of                              )

This instrument was acknowledged before me on

 by  as

 of  .

(Seal, if any)                                                                      

Title (and Rank)

My commission expires:

ARTICLE XVI.

OTHER PROVISIONS

A.Other Provisions.  This Article XVI Other Provisions is attached to and made a part of that certain Operating Agreement (this “Agreement”) dated effective May 1, 2011 by and between Encana Oil & Gas (USA) Inc. (“Encana”) and Northwest Natural Gas Company.  In the event of a conflict between the terms and conditions of this Article XVI and the terms and conditions of this Agreement, the terms and conditions of this Article XVI shall control and govern the point in conflict.

B.             Carry and Earning Agreement.  This Agreement is subject to the terms and conditions of that certain Carry and Earning Agreement dated and effective as of May 1, 2011 by and between Encana and Northwest Natural Gas Company (the “Carry and Earning Agreement”).  Except as otherwise defined in this Agreement, all capitalized terms shall have the meaning assigned to them in the Carry and Earning Agreement. In the event of a conflict between the terms and conditions of this Agreement and the terms and conditions of the Carry and Earning Agreement the terms and conditions of the Carry and Earning Agreement shall control and govern the point in conflict; provided that pursuant to Section 14.2 of the Carry and Earning Agreement certain sections of the Carry and Earning Agreement will terminate upon termination of the obligation to fund and drill Carry Wells and as to the subjects of those terminated sections identified in Section 14.2 of the Carry and Earning Agreement, this Agreement will control after that time.

C.             Conflicts. If all or parts of the Contract Area are subject to an existing operating agreement with a third party, such existing operating agreement shall control as to such third party. However, as between Operator and Non-Operator, this Agreement and the Carry and Earning Agreement shall control. In the event of any conflict or inconsistency between the terms of this Agreement and the Carry and Earning Agreement, the Carry and Earning Agreement shall prevail to the extent of such conflict. If Operator and/or Non-operator acquire the entire interest covered by an existing third party operating agreement, then such third party agreement shall be superseded and replaced in its entirety by this Agreement. The parties intend that this Agreement shall govern a Party’s election to participate in subsequent operations on the Existing Wells, Carry Wells, and any other future wells drilled in the Assigned Sections.

D.           Contract Area.  As used in this Agreement, the term “Contract Area” shall mean (i) all of the lands, Oil and Gas Leases and/or Oil andGas Interests in the Updip Area described in Exhibit A and (ii) those lands, Oil and Gas Leases and/or Oil and Gas Interests in the Downdip Area described in Exhibit A insofar as they comprise the wellbores of Carry Wells drilled pursuant to the Carry and Earning Agreement, in all cases limited to the interval correlative to the stratigraphic equivalent of the Lance Pool (as defined by Cause No. 1, Order No. 1, Docket No. 84-2003 dated April 25, 2003 of the Wyoming Oil & Gas Conservation Commission), or lands pooled therewith.

E.           Burdens.  Notwithstanding anything in Article III.B of this Agreement to the contrary, with respect to the Carry Wells and Contract Area, the burdens on the production shall be equal to and shall not exceed those listed on Exhibit A.  If any Party receives acreage support for a Carry Well from a third party, the burdens shall include any burdens reserved by such third party, but the party receiving such acreage support shall not reserve any additional burdens to itself burdening such acreage support.

After the Effective Date, if any party creates any additional burdens on the Contract Area, the party creating such additional burden shall be solely responsible for and shall pay such additional burden.  Subject to the foregoing sentence, Operator shall make payment of all burdens affecting the Contract Area and wells located on the Contract Area, and Non-Operator shall reimburse Operator for all burdens on the interest of Non-Operator.

F.Non-Consent Penalties.  The Carry Wells are obligation wells under the Carry and Earning Agreement, and neither party shall be permitted to non-consent the drilling of a Carry Well.  The non-consent penalty provided for in Article VI.B.2(b) of this Agreement shall only apply to (i) subsequent operations for a Carry Well, and (ii) operations of wells in the Updip Area others than Carry Wells.

G.Priority of Operations.  If at any time, there is more than one operation proposed in connection with any well subject to this Agreement, then unless all participating parties agree on the sequence of such operations, such proposals shall be considered and disposed of in the following order of priority:

1.           Proposals to do additional testing, coring or logging.

2. Proposals to attempt a Completion in the Initial Objective.

3. Proposals to Rework the well.

4. Proposals to Plug Back and attempt Recompletions in shallower zones, in ascending order.

5.           Proposals to Deepen the well, in descending order.

6.           Proposals to Sidetrack the well.

No party may propose any operation with respect to any well while there is in progress any operation on such well until such operation has been completed.

It is provided, however, that if, at the time said participating parties are considering any of the above operations, the hole is in such a condition that a reasonable prudent Operator would not conduct an operation in the sequence above provided for fear of placing the hole in jeopardy or losing the same prior to completing the well in the Initial Objective, such operation shall not be given priority as set forth above.

H.Termination of Operations.  Except for the drilling of Carry Wells, in the event the parties are unable to secure the requisite fifty-one percent (51%) consent to terminate an operation for the drilling, Reworking, Sidetracking, Plugging Back, Deepening, testing, or plugging of a well as provided in Article VI.F and the parties agree the condition of the hole is not in jeopardy, the party proposing to continue such operation shall bear all associated risk and expense until such operation is completed or terminated; the non-consenting party shall relinquish its interest in the well until the proceeds of the sale of such share, calculated at the well, or market value thereof if such share is not sold (after deducting applicable ad valorem, production, severance, and excise taxes, royalty, overriding royalty and other interests not excepted by Article III.C payable out of or measured by the production from such well accruing with respect to such interest until it reverts), shall equal the total of the percentages set forth in Article VI.B.2(b)(i)-(ii) of the Agreement for expenses incurred until such operation is completed or terminated.

I.Marketing Agreement.  For so long as the Marketing Agreement attached as Exhibit H remains in effect, Article VI.G shall not apply.  If the Marketing Agreement is terminated, Article VI.G shall apply as modified by Section 10 of the Carry and Earning Agreement.

J.Internal Revenue Code Election.  This Agreement is not intended to create, and shall not be construed to create, an association for profit, a trust, a joint venture, a mining partnership or other relationship of partnership, or entity of any kind between the Parties.  Notwithstanding anything to the contrary contained herein, the Parties understand and agree that the arrangement and undertakings evidenced by this Agreement, taken together, result in a partnership for purposes of federal income taxation and for purposes of certain state income tax laws which incorporate or follow federal income tax principles as to tax partnerships.  For these purposes, the Parties agree to be governed by the tax partnership provisions attached as Exhibit G, which are incorporated into and made a part of this Agreement by this reference.  For every purpose other than the above described income tax purposes and except as provided in the Carry and Earning Agreement, the Parties understand and agree that the liabilities of the of the Parties shall be several, not joint or collective, and that each Party shall be solely responsible for its own obligations.  In the event of any conflict or inconsistency between the terms and conditions of Exhibit G and the terms and conditions of this Agreement or any attachment or exhibit hereto (other than Exhibit G), the terms and conditions of Exhibit G shall govern and control.

K.Liability.  [***].

L.Liens and Security Interests.  The initial memorandum of agreement and fixture filing (the “Memorandum”) referenced in Article VII.B of this Agreement shall be in the form attached as Exhibit I, and shall be recorded in Sublette County, Wyoming.  The initial financing statement (the “Financing Statement”) referenced in Article VII.B shall be in the form attached as Exhibit J, and shall be filed with the Delaware Secretary of State.  The collateral subject to the liens described in this Agreement shall be as described in Article VII.B., and as further supplemented and described in the Memorandum and the Financing Statement.  Nothing in this Article XVI.L is intended to constrain or modify the obligation or ability of either party to execute, record, or file such memoranda of agreement, recording supplements, or other documents either party deems necessary to evidence, attach, or perfect the liens created by this Agreement.

M.Maintenance of Uniform Interest.  The Parties agree to waive the Maintenance of Uniform Interest provision in Article VIII.D only with respect to the assignments contemplated by the Carry and Earning Agreement and only to the extent assignments are made between parties to the Carry and Earning Agreement regarding the interest earned under the Carry and Earning Agreement.

N.Operations.  Notwithstanding anything in Article V.B of this Agreement to the contrary, if the Operator of existing wells or the Carry Wells sells, assigns or otherwise transfers its interest in said wells or Carry Wells, such Operator’s successor-in-interest shall have the right to vote for itself and elect itself as successor Operator.

O.Dispute Resolution.  The Parties agree to resolve all disputes concerning or relating to this Agreement pursuant to the provisions of this Section.  The Parties agree to submit all disputes to binding arbitration in Denver, Colorado.  The arbitration will be conducted according to the procedure that follows.  The arbitration proceedings shall be governed by Wyoming law and shall be conducted in accordance with the rules for Non-Administered Arbitration of Business Disputes published by The Center for Public Resources, Inc., with discovery to be conducted in accordance with the Federal Rules of Civil Procedure, and with any disputes over the scope of discovery to be determined by the Arbitrators (as defined below).  The arbitration shall be before a single Arbitrator chosen by the mutual agreement of the Parties, or if no agreement as to the identity of the Arbitrator can be reached within ten (10) days, a three-person panel of neutral Arbitrators, consisting of one person chosen by each Party, and the two Arbitrators so selected choosing the third.  The panel so chosen or the single person are referred to herein as the “Arbitrators.”  The Arbitrators shall conduct a hearing no later than sixty (60) days after submission of the matter to arbitration, and the Arbitrators shall render a written decision within thirty (30) days of the hearing.  At the hearing, the Parties shall present such evidence and witnesses as they may choose, with or without counsel.  Adherence to formal rules of evidence shall not be required, but the Arbitrators shall consider any evidence and testimony that they determine to be relevant, in accordance with procedures that they determine to be appropriate.  Any award entered in the arbitration shall be made by a written opinion stating the reasons and basis for the award made and any payment due pursuant to the arbitration shall be made within fifteen (15) days of the decision by the Arbitrators.  The decision of the Arbitrators shall be binding on the Parties, final and non-appealable, and may be filed in a court of competent jurisdiction and may be enforced by either Party as a final judgment of such court.  Each Party shall bear its own costs and expenses of the arbitration, provided, however, that the costs of employing the Arbitrators shall by shared equally by the Parties.

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

P.Well Requirements.Operator agrees to furnish information to participating Non-Operator on a current basis, including but not limited to daily drilling reports, test reports, logs and all other related reports and data.

Q.Well Connects.  Operator shall issue Non-Operator an AFE for its allocable share of the cost of construction of all well connects for all non-Carry Wells.  Non-Operator shall bear its proportionate share of the operating costs of gathering facilities as provided in the Carry and Earning Agreement.

R.Surface Facilities, Central Delivery Point, Method of Allocation:

1.   An election to participate in the drilling and completion of a non-Carry Well includes a commitment to participate in the cost of facilities beyond the wellhead connection.  The flow lines, tie-in and facilities informational AFE will accompany Operator’s notice of a new well proposal or Operator’s recommended completion attempt of the well as provided under Article VI.  The notice will identify the production facilities and Central Delivery Point (“CDP”) to which the well will be connected.

2.   Except as provided in Article XVI.R.3 of this Agreement, the Parties agree that if production from any well completed in the Contract Area should be commingled at a CDP, all production shall be allocated among the Parties in accordance with the method approved by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), as described in the Order dated May 11, 2010 for Docket No. 16-2010, or pursuant to any other applicable Order as the same may be amended from time to time. The approved method of allocation currently in use is as follows:

(a) Measurement:

The measurement of oil and gas shall comply with the requirements of BLM Onshore Orders 4 and 5 and all other applicable laws, regulations, rules, NTL's and orders issued by BLM, WOGCC or other federal, state or local governmental entity with jurisdiction over the Contract Area.

Individual wellhead volumes will be monitored and edited on a weekly basis to ensure production remains consistent with its historical trend.  Individual wellhead meter calibrations will be performed on an as needed basis as volumes deviate from its historical trend.  Custody meter calibrations will be performed on a quarterly basis or pursuant to Operator’s agreement with its third party gatherer.

(b) CDP Capital and Operating Cost Allocation:

The cost to build/install the CPD (“CDP Cost”) shall be allocated among the well or wells that will be producing to the CDP at the time the CDP is built/installed. Encana shall bear CDP Cost for Carry Wells pursuant to the Carry and Earning Agreement.  For non-Carry Wells, CDP Cost shall be allocated to (i) the owners in the wells in proportion to their before payout working interest in the well(s), if one or more owners have elected not to participate in the well, or (ii) the owners’ working interests if all owners in a well elected to participate in the well.  The allocated CDP Cost of a non-Carry Well shall be deemed to be part of the initial capital subject to standout penalties and subsequent recovery (at 100%).

CDP operating expenses shall be allocated to each working interest owner in proportion to their working interest.

(c)  Gas Production and Sales:

Actual CDP gas sales volumes (the “Custody Transfer Meter” volumes) shall be allocated to each individual well by multiplying the Custody Transfer Meter volume, in MCF, by the ratio of each well’s metered wellhead gas volume, in MCF, to the sum of

all metered wellhead gas volumes, in MCF, of all wells delivering gas to the CDP that month.  The BTU per cubic foot for produced gas volumes reported for each well shall be based on the composite sales gas BTU per cubic foot from the CDP for the month.

Each well’s allocated gas production, in MCF, shall be the sum of the MCF of sales gas allocated to the well.

(d)  Oil Production:

Actual CDP oil production, defined as CDP oil sales, (bbls) plus closing inventory (bbls) less opening inventory (bbls) shall be allocated back to each individual well by multiplying the actual CDP oil production volume, in bbls, by the ratio of each well’s metered wellhead gas volume, in MCF, to the sum of all metered wellhead gas volumes, in MCF, of all wells delivering gas to the CDP that month, provided that Non-Operator shall have no right to Condensate.  The oil gravity reported for oil production and sales volumes for each well shall be the composite gravity for oil sales from the CDP for the month.

(e)  Water Production:

CDP water production shall be allocated back to each individual well by multiplying the CDP water production volume, in bbls, by the ratio of each well’s metered wellhead gas volume, in MCF, to the sum of all metered wellhead gas volumes, in MCF, of all wells delivering gas to the CDP that month.

3. In the event that the WOGCC or the BLM require modifications to any of the allocation procedures described in Article XVI.R.2 or otherwise fail to approve any of the procedures described herein, the Parties agree the terms provided above shall be deemed to be amended in compliance with such modifications.

S.Royalties, Overriding Royalties And Other Payments.Operator shall use reasonable good faith efforts to pay or cause to be paid all royalties, shut-in royalties, minimum royalties, overriding royalties, payments out of production, or other amounts or charges which may be or become payable out of production and shall charge all such payments to the account of the party or parties responsible therefor.  However, Operator shall never be liable for a standard of performance in making such payment or payments in excess of a reasonable good faith effort to pay same prior to the due date; and no liability is to be incurred for the failure to make payment within the time, in the manner and for the amounts due through error or omission of the employees or representatives of Operator.

T.Shut-in Production.Operator shall not shut-in Non-Operator’s share of production from any well without Non-Operator’s consent, except as may be necessary for routine maintenance, equipment installation, or other similar operations.

U.Mutuality.The parties hereto acknowledge and declare that this Agreement is the result of extensive negotiations between themselves.  Accordingly, in the event of any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by either Party hereto.

V.Headings.The heading of the several articles and sections of this Agreement are for convenience only, and shall not control or affect the meaning or construction of the terms and provisions hereof.

Exhibit D

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011 by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Disclosure Statement

Sections 2.52(ii) and 6.2(viii)

Basic Contracts

ENCANA CONTRACT NO.	CONTRACT NAME	CONTRACT DATE
7140	[***]	January 1, 2010
10515	[***]	December 18, 2008
10522	[***]	January 1, 2008
9419	Programmatic Agreement among The Bureau of Land Management et al, effective June 26, 2007, regarding the Mitigation of adverse effects to Diverse Criterion Historic Properties within the [***].	June 26, 2007
10800	[***]	August 11, 2006
7008	Communitization Agreement No. 168669, approved March 16, 2003, Encana Oil & Gas (USA) Inc., as operator	March 16, 2006
9418	US Department of Interior Jonah Infill Development Programmatic Agreement - Record of Decision dated March 15, 2006  - Jonah Environmental Impact Statement.	March 14, 2006
7007	[***]	June 1, 2005
5250	Communitization Agreement No. 156992, approved January 17, 2003, by and between McMurry Oil Company, et al, and State of Wyoming.	January 17, 2003
5251	Communitization Agreement No. 156993, approved January 17, 2003, by and between McMurry Oil Company, et al, and State of Wyoming.	January 17, 2003
5265	[***]	June 1, 1994
5263	[***]	March 9, 1992

Section 6.1(iv)

OPUC approval pursuant to Section 7 of the Carry and Earning Agreement

Biodiversity Conservation Alliance v. United States Bureau of Land Management, et al., Case No. 10-8064, U.S. Court of Appeals for the Tenth Circuit (filed August 10, 2010).

Section 6.1(vii)

None

Section 6.1(viii)

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

OPUC approval pursuant to Section 7 of the Carry and Earning Agreement

Section 6.2(i)

None

Section 6.1(v)

None

Section 6.2(vii)

None

Section 6.2(ix)

As disclosed to ENVIRON International Corp.

in response to Document Request dated February 1, 2011

from [***]

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

Exhibit E

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Wire Instructions for NWN Share

ENCANA WIRE TRANSFER INSTRUCTIONS

[***]

Page 1 of 1

Carry and Earning Agreement – Exhibit E

Exhibit F

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

GAS GATHERING AGREEMENT ATTORNMENT LETTER

Encana Oil & Gas (USA) Inc.                                                                           Northwest Natural Gas Company

370 Seventeenth Street, Suite 1700                                                                                     220 NW Second Avenue

Denver, Colorado  80202                                                                                     Portland, Oregon  97209-3991

[***]

Subject: [***]

Ladies and Gentlemen:

1.           [***]

2.           [***]

3.           [***]

4.           [***]

5.           [***]

6.           [***]

7.           Counterparts.  This document may be executed in any number of counterparts, each of which when combined and taken together, shall be considered but one and the same document.

8.           [***]

 [Signature Page Follows]

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

ENCANA OIL & GAS (USA) INC.

Agreed to and approved this ___5th____ day of

_______April___________, 2011.

By:    /s/                                                 

Name:  John B. Jones                                                    

Title:  Vice President, USA Midstream                                                              

NORTHWEST NATURAL GAS COMPANY

Agreed to and approved this ___12th____ day of

________April__________, 2011.

By:     /s/                                                                                     

Name:   Gregg Kantor                                                   

Title:   President & CEO                                                             

[***]

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

SCHEDULE I

Updip Area:                                Township 29 North, Range 108 West of the 6th P.M.

Section 32:  All

Section 33:  All

Section 34:  All

Downdip Area:                                Township 29 North, Range 108 West of the 6th P.M.

Section 9:    All

Section 10:  All

Section 11:  SW/4

Section 14:  All

Section 15:  All

Section 16:  All

Section 17:  All

All within Sublette County, Wyoming.

SCHEDULE II

[***]

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

GAS PROCESSING AGREEMENT ATTORNMENT LETTER

Encana Oil & Gas (USA) Inc.                                                                           Northwest Natural Gas Company

370 Seventeenth Street, Suite 1700                                                                                     220 NW Second Avenue

Denver, Colorado 80202                                                                                     Portland, Oregon 97209-3991

[***]

Subject:                 Transfer of Interests in Dedicated Lands

Ladies and Gentlemen:

1.           [***]

2.           [***]

3.           [***]

4.           [***]

5.           [***].

6.           [***].

7.           Counterparts.  This document may be executed in any number of counterparts, each of which when combined and taken together, shall be considered but one and the same document.

8.           [***].

[Signature Page Follows]

Carry and Earning Agreement – Exhibit F

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

ENCANA OIL & GAS (USA) INC.

Agreed to and approved this ____5th___ day of

_____April_____________, 2011.

By:  /s/                                                     

Name:  John B. Jones                                                   

Title:  Vice President, USA Midstream                                                              

NORTHWEST NATURAL GAS COMPANY

Agreed to and approved this ___12th____ day of

________April__________, 2011.

By:  /s/                                                                                         

Name:  Gregg Kantor                                                    

Title: President & CEO                                                               

[***]

Carry and Earning Agreement – Exhibit F

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

SCHEDULE I

Updip Area:                                Township 29 North, Range 108 West of the 6th P.M.

Section 32:  All

Section 33:  All

Section 34:  All

Downdip Area:                                Township 29 North, Range 108 West of the 6th P.M.

Section 9:    All

Section 10:  All

Section 11:  SW/4

Section 14:  All

Section 15:  All

Section 16:  All

Section 17:  All

All within Sublette County, Wyoming.

Carry and Earning Agreement – Exhibit F

SCHEDULE II

[***]

Carry and Earning Agreement – Exhibit F

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.

Exhibit G

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Composite Producer Price Index

U.S. Bureau of Labor Statistics - Producer Price Index Data

Industries and their products  (NAICS Classifications)

Oil and Gas Industry Data - NAICS Series 211xxx and 213xxx

O&G Industry - Drilling O&G Wells Indexes

Series Id:  PCU213111 - 213111

Industry:   Drilling oil and gas wells

Product:    Same

Base Date:  1985-12

	December 2010
INDEX:	335.90
Weight @20%:	67.18

Series Id:  PCU213112 - 213112

Industry:  Support Activities for oil and gas operations

Product:   Same

Base Date:  1985-12

	December 2010
INDEX:	182.10
Weight @65%:	118.37

Metal & Metal Products - Steel Pipe & Tube Index

Series Id:  WPU0101706 – 0101706

Commodity Group - Metal & Metal Products

Product:   Steel Pipe & Tube

Base Date: 1982-06

	December 2010
INDEX:	249.2
Weight @15%:	37.38

Composite Index:                                     222.93

Page 1 of 1

Carry and Earning Agreement – Exhibit G

Exhibit H

Attached to and made a part of that Carry and Earning Agreement

dated and effective as of May 1, 2011, by and between

Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company

Drilling Schedule
	Well Count
May-June 2011	[***]
July - Sept 2011	[***]
Oct - Dec 2011	[***]
[***]	[***]
[***]	[***]
July - Sept 2012	[***]
Oct - Dec 2012	[***]
Jan - March 2013	[***]
April-June 2013	[***]
[***]	[***]
[***]	[***]
Jan - March 2014	[***]
April - June 2014	[***]
July - Sept 2014	[***]
Oct - Dec 2014	[***]
Jan - March 2015	[***]
April -June 2015	[***]
July - Sept 2015	[***]
Oct - Dec 2015	[***]
Jan - March 2016	[***]

TOTAL       [***]

Page 1 of 1

Carry and Earning Agreement – Exhibit H

[***] This confidential information has been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment

EX-12

															EXHIBIT 12
		NORTHWEST NATURAL GAS COMPANY
		Ratio of Earnings to Fixed Charges
		Thousands, except per share amount
		(Unaudited)
													12 Months		Three Months(1)
													Ended		Ended
			Year Ended December 31,										Mar 31,		Mar 31,
			2010		2009		2008		2007		2006		2011		2011
Fixed Charges, as defined:
	Interest on Long-Term Debt		$	39,198	$	37,447	$	33,605	$	34,294	$	34,651	$	38,645	$	9,281
	Other Interest			1,587		1,937		4,022		4,116		4,648		1,747		448
	Amortization of Debt Discount and Expense			1,766		1,503		700		711		716		1,751		428
	Interest Portion of Rentals			2,130		1,735		1,551		1,523		1,465		2,341		620
	Total Fixed Charges, as defined		$	44,681	$	42,622	$	39,878	$	40,644	$	41,480	$	44,484	$	10,777
Earnings, as defined:
	Net Income		$	72,667	$	75,122	$	69,525	$	74,497	$	63,415	$	69,832	$	40,773
	Taxes on Income			49,462		46,671		40,678		44,060		36,234		47,280		27,854
	Fixed Charges, as above			44,681		42,622		39,878		40,644		41,480		44,484		10,777
	Total Earnings, as defined		$	166,810	$	164,415	$	150,081	$	159,201	$	141,129	$	161,596	$	79,404
Ratio of Earnings to Fixed Charges				3.73		3.86		3.76		3.92		3.40		3.63		7.37
(1)		A significant part of the business of NW Natural is of a seasonal nature; therefore, the ratios of earnings to fixed charges for the interim periods are not necessarily indicative of the results for a full year.

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Gregg S. Kantor, certify that:

1.           I have reviewed this quarterly report on Form 10-Q for the three months ended March 31, 2011 of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:           May 4, 2011

/s/ Gregg S. Kantor                                                      

Gregg S. Kantor

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, David H. Anderson, certify that:

1.           I have reviewed this quarterly report on Form 10-Q for the three months ended March 31, 2011 of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:           May 4, 2011

/s/ David H. Anderson                                                                

David H. Anderson

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

NORTHWEST NATURAL GAS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

Each of the undersigned, GREGG S. KANTOR, the President and Chief Executive Officer, and DAVID H. ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:

1.           The Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (the Report) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

             IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 4th day of May 2011.

/s/ Gregg S. Kantor                                                      

Gregg S. Kantor

President and Chief Executive Officer

/s/ David H. Anderson                                                 

David H. Anderson

Senior Vice President and

Chief Financial Officer

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.